m,UK Patent n«GB m.2 348 223 JB
(45) Date of publication: 24.09.2003
(54) Title ofthe invention: Method of creating a casing in a borehole
(51) Int CI 7 : E21B 7/20 33/14 43/10
(21) Application No:
(22) Date of Filing:
(30) Priority Data:
(31) 60124042
0005399.1
06.03.2000
(32) 11.03.1999 (33) US
(60) Parent of Application No(s)
0310101.1, 0310118.5, 0310099.7, 0310090.6,
0310104.5 under Section 15(4) ofthe Patents
Act 1977
(43) Date A Publication:
27.09.2000
(52) UK CL (Edition V ):
E1F FCM FJT FLA
(56) Documents Cited:
6B 2347445 A
EP 0881354 A
WO 1998/000626 A
GB 2344606 A
WO 2000/077431 A
US 6070671 A
(58) Field of Search:
As for published application 2348223 A viz:
UK CL (Edition R ) E1F FJT FLA
INT CL 7 E21B
Other Online: WPI,EPODOC JAPIO
updated as appropriate
(72) Inventor(s):
Robert Lance Cook
David Paul Brisco
R Bruce Stewart
Lev Ring
Richard Cart Haul
Robert Donald Mack
Alan B Duell
(73) Proprietor(s):
Shell International Research
Maatschhappij B.V.
(Incorporated in the Netherlands)
Carol van Bylandtlaan 30, NL-2596 HR,
The Hague, Netherlands
(74) Agent and/or Address for Service:
Haseltine Lake & Co
Imperial House, 15-19 Kingsway,
LONDON, WC2B 6UD, United Kingdom
Additional Fields
UK CL (Edition S ) E1F FCM
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METHOD OF CREATING A CASING IN A BOREHOLE
Background of the Invention
This invention relates generally to wellbore casings, and in particular to wellbore
casings that are formed using expandable tubing.
Conventionally, when a wellbore is created, a number of casings are installed in
5 the borehole to prevent collapse of the borehole wall and to prevent undesired outflow of
drilling fluid into the formation or inflow of fluid from the formation into the borehole.
The borehole is drilled in intervals whereby a casing which is to be installed in a lower
borehole interval is lowered through a previously installed casing of an upper borehole
interval. As a consequence of this procedure the casing of the lower interval is of smaller
10 diameter than the casing of the upper interval. Thus, the casings are in a nested
arrangement with casing diameters decreasing in downward direction. Cement annuli are
provided between the outer surfaces of the casings and the borehole wall to seal the
casings from the borehole wall. As a consequence of this nested arrangement a relatively
large borehole diameter is required at the upper part of the wellbore. Such a large
15 borehole diameter involves increased costs due to heavy casing handling equipment, large
drill bits and increased volumes of drilling fluid and drill cuttings. Moreover, increased
drilling rig time is involved due to required cement pumping, cement hardening, required
equipment changes due to large variations in hole diameters drilled in the course of the
well, and the large volume of cuttings drilled and removed.
20 Conventionally, at the surface end of the wellbore, a wellhead is formed that
typically includes a surface casing, a number of production and/or drilling spools, valving,
and a Christmas tree. Typically the wellhead further includes a concentric arrangement
of casings including a production casing and one or more intermediate casings. The
casings are typically supported using load bearing slips positioned above the ground. The
25 conventional design and construction of wellheads is expensive and complex.
Conventionally, a wellbore casing cannot be formed during the drilling of a
wellbore. Typically, the wellbore is drilled and then a wellbore casing is formed in the
newly drilled section of the wellbore. This delays the completion of a well.
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The present invention is directed to overcoming one or more of the limitations of
the existing procedures for forming wellbores and wellheads.
Summary of the Invention
According to a first aspect of the present invention there is provided a method of
5 creating a casing in a borehole located in a subterranean formation, comprising: installing
a tubular liner and a mandrel in the borehole; injecting fluidic material into the borehole;
pressurizing a portion of an interior region of the tubular liner; radially expanding at least
a portion of the liner in the borehole by extruding at least a portion of the liner off of the
mandrel; and drilling out the borehole while extruding the liner off of the mandrel.
10 Preferably, the injecting includes injecting a non hardenable fluidic material into
an interior region of the tubular liner below the mandrel.
Preferably, the annular region is fluidically isolated from the interior region before
injecting the non hardenable fluidic material into the interior region.
Preferably, the mandrel is maintained in a substantially stationary position within
15 the borehole during the extrusion of the liner and the drilling out of the bore hole.
Preferably, the injecting of the non hardenable fluidic material is provided at
operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000
gallons/min (34.47 to 620.53 bar and 151.42 to 1 1356.24 litres/min).
Preferably, the injecting of non hardenable fluidic material is provided at reduced
20 operating pressures and flow rates during an end portion of the extruding.
Preferably, the fluidic material is injected below the mandrel.
Preferably, a region of the tubular liner below the mandrel is pressurized.
Preferably, the region of the tubular liner below the mandrel is pressurized to
pressures ranging from 500 to 9,000 psi (34.47 to 620.53 bar).
25 Preferably, an interior region of the tubular liner is isolated from an exterior region
of the tubular liner.
Preferably, the interior region of the tubular liner is isolated from the region
exterior to the tubular liner by inserting one or more plugs into the injected fluidic
material.
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Preferably, a hardenable fluidic sealing material is injected into the annulus
between the extruded liner and the borehole.
Preferably, the tubular liner is overlapped with an existing wellbore casing.
Preferably, the overlap between the tubular liner and the existing wellbore casing
5 is sealed.
Preferably, th extruded tubular liner is supported using the overlap with the
existing wellbore casing.
Preferably the integrity of the seal in the overlap between the tubular liner and the
existing wellbore casing is tested.
10 Preferably, a variable axial force is applied onto the bottom of the borehole.
Preferably, the surface of the mandrel is lubricated
Preferably, the method further comprises absorbing shock.
Preferably the mandrel is caught upon the completion of the extruding.
Preferably, the mandrel is expanded in a radial direction.
15 Preferably, the mandrel is drilled out
Preferably, the mandrel is supported with coiled tubing.
Preferably, the wall thickness of the tubular member is variable.
Preferably, the mandrel is coupled to a drillable shoe.
According to a second aspect of the present invention there is provided a method
20 of joining a second tubular member to a first tubular member, the first tubular member
having an inner diameter greater than an outer diameter of the second tubular member,
comprising: positioning a mandrel within an interior region of the second tubular member;
pressurizing a portion of the interior region of the second tubular member, extruding at
least a portion of the second tubular member offof the mandrel into engagement with the
25 first tubular member; and drilling out the borehole while extruding the second tubular
member off of the mandrel.
According to a third aspect of the present invention there is provided a method of
joining a second tubular member to a first tubular member, the first tubular member
having an inner diameter greater than an outer diameter of the second tubular member,
30 comprising: positioning a mandrel within an interior region of the second tubular member;
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pressurizing a portion of the interior region of the mandrel; displacing the mandrel
relative to the second tubular member; extruding at least a portion of the second tubular
member offof the mandrel into engagement with the first tubular member; and drilling out
the borehole while extruding the second tubular member off of the mandrel.
5 Preferably, the pressurizing of the portion of the interior region of the second
tubular member is provided at operating pressures ranging from about 500 to 9,000 psi
(34.47 to 620.53 bar).
Preferably, the pressurizing of the portion of the interior region of the second
tubular member is provided at reduced operating pressures during a latter portion of the
10 extruding.
Preferably, the interface between the first and second tubular member is sealed.
Preferably, the extruded second tubular member is supported using the interface
with the first tubular member.
Preferably, the surface of the mandrel is lubricated.
15 Preferably, the method further comprises absorbing shock.
Preferably, the mandrel is expanded in a radial direction.
Preferably, the first and second tubular members are positioned in an overlapping
relationship.
Preferably, an interior of the second tubular member is fluidically isolated from an
20 exterior region of the second tubular member.
Preferably, the interior region of the second tubular member is fluidicly isolated
from the region exterior to the second tubular member by injecting one or more plugs into
the interior of the second tubular member.
Preferably, the pressurizing of the portion of the interior region of the second
25 tubular member is provided by injecting a fluidic material at operating pressures and flow
rates ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/minute (34.47 to 620.53
bar and 1 5 1 .42 to 1 1 356.24 litres/minute).
Preferably, fluidic material is injected beyond the mandrel.
Preferably, a region of the second tubular member beyond the mandrel is
30 pressurized.
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Preferably, the region of the second tubular member beyond the mandrel is
pressurized to pressures ranging from about 500 to 9,000 psi (34.47 to 620.53 bar).
Preferably, the first tubular member comprises an existing section of a wellbore.
Preferably, the interface between the first and second tubular members is sealed.
5 Preferably, the extruded second tubular member is supported using the first tubular
member.
Preferably, the integrity of the seal in the interface between the first tubular
member and the second tubular member is tested.
Preferably, the mandrel is caught upon the completion of the extruding.
10 Preferably, the mandrel is drilled out.
Preferably, the mandrel is supported with coiled tubing.
Preferably, the mandrel is coupled to a driilable shoe.
Brief Description of the Drawings
For a better understanding of the present invention and to show how the same may
15 be carried into effect reference will now be made, by way of example, to the
accompanying drawings, in which:-
FIG. 1 is a fragmentary cross-sectional view illustrating the drilling of a new
section of a well borehole.
FIG. 2 is a fragmentary cross-sectional view illustrating the placement of an
20 embodiment of an apparatus for creating a casing within the new section of the well
borehole.
FIG. 3 is a fragmentary cross-sectional view illustrating the injection of a first
quantity of a fluidic material into the new section of the well borehole.
FIG. 3a is another fragmentary cross-sectional view illustrating the injection of a
25 first quantity of a hardenable fluidic sealing material into the new section of the well
borehole,
FIG. 4 is a fragmentary cross-sectional view illustrating the injection of a second
quantity of a fluidic material into the new section of the well borehole.
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FIG. 5 is a fragmentary cross-sectional view illustrating the drilling out of a portion
of the cured hardenable fluidic sealing material from the new section of the well borehole.
FIG. 6 is a cross-sectional view of an embodiment of the overlapping joint between
adjacent tubular members.
5 FIG. 7 is a fragmentary cross-sectional view of a preferred embodiment of the
apparatus for creating a casing within a well borehole.
FIG. 8 is a fragmentary cross-sectional illustration of the placement of an expanded
tubular member within another tubular member.
FIG. 9 is a cross-sectional illustration of a preferred embodiment of an apparatus
10 for forming a casing including a drillable mandrel and shoe.
FIG. 9a is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 9b is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 9c is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 10a is a cross-sectional illustration of a wellbore including a pair of adjacent
15 overlapping casings.
FIG. 10b is a cross-sectional illustration of an apparatus and method for creating
a tie-back liner using an expandible tubular member.
FIG. 10c is a cross-sectional illustration of the pumping of a fluidic sealing
material into the annular region between the tubular member and the existing casing.
20 FIG. lOd is a cross-sectional illustration of the pressurizing of the interior of the
tubular member below the mandrel.
FIG. 1 Oe is a cross-sectional illustration of the extrusion of the tubular member off
of the mandrel.
FIG. 1 Of is a cross-sectional illustration of the tie-back liner before drilling out the
25 shoe and packer.
FIG. lOg is a cross-sectional illustration of the completed tie-back liner created
using an expandible tubular member.
FIG. 1 la is a fragmentary cross-sectional view illustrating the drilling of a new
section of a well borehole.
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FIG. 1 lb is a fragmentary cross-sectional view illustrating the placement of an
embodiment of an apparatus for hanging a tubular liner within the new section of the well
borehole.
FIG. 1 lc is a fragmentary cross-sectional view illustrating the injection of a first
5 quantity of a hardenable fluidic sealing material into the new section of the well borehole.
FIG. lid is a fragmentary cross-sectional view illustrating the introduction of a
wiper dart into the new section of the well borehole.
FIG. 1 le is a fragmentary cross-sectional view illustrating the injection of a second
quantity of a hardenable fluidic sealing material into the new section of the well borehole.
10 FIG. 1 If is a fragmentary cross-sectional view illustrating the completion of the
tubular liner.
FIG. 12 is a cross-sectional illustration of a preferred embodiment of a wellhead
system utilizing expandable tubular members.
FIG. 13 is a partial cross-sectional illustration of a preferred embodiment of the
15 wellhead system of FIG. 12.
FIG. 14a is an illustration of the formation of an embodiment of a mono-diameter
wellbore casing.
FIG. 14b is another illustration of the formation of the mono-diameter wellbore
casing.
20 FIG. 14c is another illustration of the formation of the mono-diameter wellbore
casing.
FIG. 14d is another illustration of the formation of the mono-diameter wellbore
casing.
FIG. 14e is another illustration of the formation of the mono-diameter wellbore
25 casing.
FIG. 14f is another illustration of the formation of the mono-diameter wellbore
casing.
FIG. 1 5 is an illustration of an embodiment of an apparatus for expanding a tubular
member.
30 FIG. 1 5a is another illustration of the apparatus of FIG. 1 5 .
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FIG. 15b is another illustration of the apparatus of FIG. 15.
FIG. 16 is an illustration of an embodiment of an apparatus for forming a mono-
diameter wellbore casing.
FIG. 1 7 is an illustration of an embodiment of an apparatus for expanding a tubular
5 member.
FIG. 17a is another illustration of the apparatus of FIG. 16.
FIG. 17b is another illustration of the apparatus of FIG. 16.
FIG. 1 8 is an illustration of an embodiment of an apparatus for forming a mono-
diameter wellbore casing.
10 FIG. 19 is an illustration of another embodiment of an apparatus for expanding a
tubular member.
FIG. 19a is another illustration of the apparatus of FIG. 17.
FIG. 19b is another illustration of the apparatus of FIG. 17.
FIG. 20 is an illustration of an embodiment of an apparatus for forming a mono-
15 diameter wellbore casing.
FIG. 21 is an illustration of the isolation of subterranean zones using expandable
tubulars.
FIG. 22a is a fragmentary cross-sectional illustration of an embodiment of an
apparatus for forming a wellbore casing while drilling a welbore.
20 FIG. 22b is another fragmentary cross-sectional illustration of the apparatus of FIG.
22a.
FIG. 22c is another fragmentary cross-sectional illustration of the apparatus of FIG.
22a.
FIG. 22d is another fragmentary cross-sectional illustration of the apparatus ofFIG.
25 22a.
Detailed Description of the Illustrative Embodiments
Referring initially to Figs. 1-5, an embodiment of an apparatus and method for
forming a wellbore casing within a subterranean formation will now be described. As
illustrated in Fig. 1, a wellbore 100 is positioned in a subterranean formation 105. The
-8-
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wellbore 100 includes an existing cased section 1 10 having a tubular casing 115 and an
annular outer layer of cement 1 20.
In order to extend the wellbore 100 into the subterranean formation 105, a drill
string 125 is used in a well known manner to drill out material from the subterranean
5 formation 105 to form a new section 130.
As illustrated in Fig. 2, an apparatus 200 for forming a wellbore casing in a
subterranean formation is then positioned in the new section 1 30 of the wellbore 1 00. The
apparatus 200 preferably includes an expandable mandrel or pig 205, a tubular member
210, a shoe 215, a lower cup seal 220, an upper cup seal 225, a fluid passage 230, a fluid
10 passage 235, a fluid passage 240, seals 245, and a support member 250.
The expandable mandrel 205 is coupled to and supported by the support member
250. The expandable mandrel 205 is preferably adapted to controllably expand in a radial
direction. The expandable mandrel 205 may comprise any number of conventional
commercially available expandable mandrels modified in accordance with the teachings
15 of the present disclosure. In a preferred embodiment, the expandable mandrel 205
comprises a hydraulic expansion tool as disclosed in U.S. Patent No. 5,348,095, the
contents of which are incorporated herein by reference, modified in accordance with the
teachings of the present disclosure.
The tubular member 2 1 0 is supported by the expandable mandrel 205. The tubular
20 member 210 is expanded in the radial direction and extruded off of the expandable
mandrel 205. The tubular member 210 may be fabricated from any number of
conventional commercially available materials such as, for example, Oilfield Country
Tubular Goods (OCTG), 13 chromium steel tubing/casing, or plastic tubing/casing. In
a preferred embodiment, the tubular member 210 is fabricated from OCTG in order to
25 maximize strength after expansion. The inner and outer diameters of the tubular member
210 may range, for example, from approximately 0.75 to 47 inches and 1 .05 to 48 inches
(1.905 to 119.38 centimetres and 2.667 to 121.92 centimetres), respectively. In a
preferred embodiment, the inner and outer diameters of the tubular member 210 range
from about 3 to 15.5 inches and 3.5 to 16 inches (7.62 to 39.37 centimetres and 8.89 to
30 40.64 centimetres), respectively in order to optimally provide minimal telescoping effect
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in the most commonly drilled wellbore sizes. The tubular member 210 preferably
comprises a solid member.
In a preferred embodiment, the end portion 260 of the tubular member 210 is
slotted, perforated, or otherwise modified to catch or slow down the mandrel 205 when
5 it completes the extrusion of tubular member 2 10. In a preferred embodiment, the length
of the tubular member 2 1 0 is limited to minimize the possibility of buckling. For typical
tubular member 2 1 0 materials, the length of the tubular member 2 1 0 is preferably limited
to between about 40 to 20,000 feet (12. 192 to 6096.00 metres) in length.
The shoe 215 is coupled to the expandable mandrel 205 and the tubular member
10 210. The shoe 215 includes fluid passage 240. The shoe 2 1 5 may comprise any number
of conventional commercially available shoes such as, for example, Super Seal II float
shoe, Super Seal II Down- Jet float shoe or a guide shoe with a sealing sleeve for a latch
down plug modified in accordance with the teachings of the present disclosure. In a
preferred embodiment, the shoe 215 comprises an aluminum down-jet guide shoe with a
1 5 sealing sleeve for a latch-down plug available from Halliburton Energy Services in Dallas,
TX, modified in accordance with the teachings of the present disclosure, in order to
optimally guide the tubular member 210 in the wellbore, optimally provide an adequate
seal between the interior and exterior diameters of the overlapping joint between the
tubular members, and to optimally allow the complete drill out of the shoe and plug after
20 the completion of the cementing and expansion operations.
In a preferred embodiment, the shoe 215 includes one or more through and side
outlet ports in fluidic communication with the fluid passage 240. In this manner, the shoe
2 1 5 optimally injects hardenable fluidic sealing material into the region outside the shoe
215 and tubular member 210. In a preferred embodiment, the shoe 215 includes the fluid
25 passage 240 having an inlet geometry that can receive a dart and/or a ball sealing member.
In this manner, the fluid passage 240 can be optimally sealed off by introducing a plug,
dart and/or ball sealing elements into the fluid passage 230.
The lower cup seal 220 is coupled to and supported by the support member 250.
The lower cup seal 220 prevents foreign materials from entering the interior region of the
30 tubularmember210adjacenttotheexpandablemandrel205. The lower cup seal 220 may
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comprise any number of conventional commercially available cup seals such as, for
example, TP cups, or Selective Injection Packer (SIP) cups modified in accordance with
the teachings of the present disclosure. In a preferred embodiment, the lower cup seal 220
comprises a SIP cup seal, available from Halliburton Energy Services in Dallas, TX in
5 order to optimally block foreign material and contain a body of lubricant
The upper cup seal 225 is coupled to and supported by the support member 250.
The upper cup seal 225 prevents foreign materials from entering the interior region of the
tubular member 2 1 0. The upper cup seal 225 may comprise any number of conventional
commercially available cup seals such as, for example, TP cups or SIP cups modified in
10 accordance with the teachings of the present disclosure. In a preferred embodiment, the
upper cup seal 225 comprises a SIP cup, available from Halliburton Energy Services in
Dallas, TX in order to optimally block the entry of foreign materials and contain a body
of lubricant.
The fluid passage 230 permits fluidic materials to be transported to and from the
15 interior region of the tubular member 2 10 below the expandable mandrel 205. The fluid
passage 230 is coupled to and positioned within the support member 250 and the
expandable mandrel 205. The fluid passage 230 preferably extends from a position
adjacent to the surface to the bottom of the expandable mandrel 205. The fluid passage
230 is preferably positioned along a centerline of the apparatus 200.
20 The fluid passage 230 is preferably selected, in the casing running mode of
operation, to transport materials such as drilling mud or formation fluids at flow rates and
pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi (0 to 1 1 356.24
litres/minute and 0 to 620.528 bar) in order to minimize drag on the tubular member being
run and to minimize surge pressures exerted on the wellbore which could cause a loss of
25 wellbore fluids and lead to hole collapse,
The fluid passage 235 permits fluidic materials to be released from the fluid
passage 230. In this manner, during placement of the apparatus 200 within the new
section 1 30 of the wellbore 100, fluidic materials 255 forced up the fluid passage 230 can
be released into the wellbore 1 00 above the tubular member 2 1 0 thereby minimizing surge
30 pressures on the wellbore section 1 30. The fluid passage 23 5 is coupled to and positioned
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within the support member 250. The fluid passage is further fluidicly coupled to the fluid
passage 230.
The fluid passage 235 preferably includes a control valve for controllably opening
and closing the fluid passage 235. In a preferred embodiment, the control valve is
5 pressure activated in order to controllably minimize surge pressures. The fluid passage
235 ispreferably positioned substantially orthogonal to the centerlineof the apparatus 200.
The fluid passage 235 is preferably selected to convey fluidic materials at flow
rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi (0 to
1 1356.24 litres/minute and 0 to 620.528 bar) in order to reduce the drag on the apparatus
10 200 during insertion into the new section 130 of the wellbore 100 and to minimize surge
pressures on the new wellbore section 130.
The fluid passage 240 permits fluidic materials to be transported to and from the
region exterior to the tubular member 210 and shoe 215. The fluid passage 240 is coupled
to and positioned within the shoe 215 in fluidic communication with the interior region
15 of the tubular member 210 below the expandable mandrel 205. The fluid passage 240
preferably has a cross-sectional shape that permits a plug, or other similar device, to be
placed in fluid passage 240 to thereby block further passage of fluidic materials. In this
manner, the interior region of the tubular member 210 below the expandable mandrel 205
can be fluidicly isolated from the region exterior to the tubular member 2 1 0. This permits
20 the interior region of the tubular member 210 below the expandable mandrel 205 to be
pressurized. The fluid passage 240 is preferably positioned substantially along the
centerline of the apparatus 200.
The fluid passage 240 is preferably selected to convey materials such as cement,
drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000
25 gallons/minute and 0 to 9,000 psi (0 to 1 1356.24 litres/minute and 0 to 620.528 bar) in
order to optimally fill the annular region between the tubular member 210 and the new
section 130 of the wellbore 100 with fluidic materials. In a preferred embodiment, the
fluid passage 240 includes an inlet geometry that can receive a dart and/or a ball sealing
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member. In this manner, the fluid passage 240 can be sealed off by introducing a plug,
dart and/or ball sealing elements into the fluid passage 230.
The seals 245 are coupled to and supported by an end portion 260 of the tubular
member 210. The seals 245 are further positioned on an outer surface 265 of the end
5 portion 260 of the tubular member 210. The seals 245 permit the overlapping joint
between the end portion 270 of the casing 1 1 5 and the portion 260 of the tubular member
210 to be fluidicly sealed. The seals 245 may comprise any number of conventional
commercially available seals such as, for example, lead, rubber, Teflon (RTM), or epoxy
seals modified in accordance with the teachings of the present disclosure. In a preferred
10 embodiment, the seals 245 are molded from Stratalock epoxy available from Halliburton
Energy Services in Dallas, TX in order to optimally provide a load bearing interference
fit between the end 260 of the tubular member 2 1 0 and the end 270 of the existing casing
115.
In a preferred embodiment, the seals 245 are selected to optimally provide a
15 sufficient frictional force to support the expanded tubular member 2 1 0 from the existing
casing 115. In a preferred embodiment, the frictional force optimally provided by the
seals 245 ranges from about 1,000 to 1,000,000 lbf(0.478803 to478.803 bar) in order to
optimally support the expanded tubular member 210.
The support member 250 is coupled to the expandable mandrel 205, tubular
20 member 210, shoe 215, and seals 220 and 225. The support member 250 preferably
comprises an annular member having sufficient strength to carry the apparatus 200 into
the new section 1 30 of the wellbore 1 00. In a preferred embodiment, the support member
250 further includes one or more conventional centralizers (not illustrated) to help
stabilize the apparatus 200. In a preferred embodiment, the support member 250
25 comprises coiled tubing.
In a preferred embodiment, a quantity of lubricant 275 is provided in the annular
region above the expandable mandrel 205 within the interior of the tubular member 210.
In this manner, the extrusion of the tubular member 210 off of the expandable mandrel
205 is facilitated. The lubricant 275 may comprise any number of conventional
30 commercially available lubricants such as, for example, Lubriplate (RTM), chlorine based
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lubricants, oil based lubricants or Climax 1500 Antisieze (3100). In a preferred
embodiment, the lubricant 275 comprises Climax 1500 Antisieze (3100) available from
Climax Lubricants and Equipment Co. in Houston, TX in order to optimally provide
optimum lubrication to faciliate the expansion process.
5 In a preferred embodiment, the support member 250 is thoroughly cleaned prior
to assembly to the remaining portions of the apparatus 200. In this manner, the
introduction of foreign material into the apparatus 200 is minimized. This minimizes the
possibility of foreign material clogging the various flow passages and valves of the
apparatus 200.
10 In a preferred embodiment, before or after positioning the apparatus 200 within the
new section 1 30 of the wellbore 1 00, a couple of wellbore volumes are circulated in order
to ensure that no foreign materials are located within the wellbore 100 that might clog up
the various flow passages and valves of the apparatus 200 and to ensure that no foreign
material interferes with the expansion process.
15 As illustrated in Fig. 3, the fluid passage 235 is then closed and a hardenable fluidic
sealing material 305 is then pumped from a surface location into the fluid passage 230.
The material 305 then passes from the fluid passage 230 into the interior region 3 1 0 of the
tubular member 210 below the expandable mandrel 205. The material 305 then passes
from the interior region 310 into the fluid passage 240. The material 305 then exits the
20 apparatus 200 and fills the annular region 3 1 5 between the exterior of the tubular member
2 1 0 and the interior wall of the new section 1 30 of the wellbore 1 00. Continued pumping
of the material 305 causes the material 305 to fill up at least a portion of the annular region
315.
The material 305 is preferably pumped into the annular region 3 1 5 at pressures and
25 flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min (0
to 344.738 bar and 0 to 561 8. 12 litres/minute), respectively. The optimum flow rate and
operating pressures vary as a function of the casing and wellbore sizes, wellbore section
length, available pumping equipment, and fluid properties of the fluidic material being
pumped. The optimum flow rate and operating pressure are preferably determined using
30 conventional empirical methods.
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The hardenable fluidic sealing material 305 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such as, for
example, slag mix, cement or epoxy. In a preferred embodiment, the hardenable fluidic
sealing material 305 comprises a blended cement prepared specifically for the particular
5 well section being drilled from Halliburton Energy Services in Dallas, TX in order to
provide optimal support for tubular member 210 while also maintaining optimum flow
characteristics so as to minimize difficulties during the displacement of cement in the
annular region 315. The optimum blend of the blended cement is preferably determined
using conventional empirical methods.
10 The annular region 315 preferably is filled with the material 305 in sufficient
quantities to ensure that, upon radial expansion of the tubular member 210, the annular
region 315 of the new section 130 of the wellbore 100 will be filled with material 305.
In a particularly preferred embodiment, as illustrated in Fig. 3a, the wall thickness
and/or the outer diameter of the tubular member 2 1 0 is reduced in the region adjacent to
15 the mandrel 205 in order optimally permit placement of the apparatus 200 in positions in
the wellbore with tight clearances. Furthermore, in this manner, the initiation of the radial
expansion of the tubular member 210 during the extrusion process is optimally facilitated.
As illustrated in Fig. 4, once the annular region 3 1 5 has been adequately filled with
material 305, a plug 405, or other similar device, is introduced into the fluid passage 240
20 thereby fluidicly isolating the interior region 310 from the annular region 315. In a
preferred embodiment, a non-hardenable fluidic material 306 is then pumped into the
interior region 310 causing the interior region to pressurize. In this manner, the interior
of the expanded tubular member 210 will not contain significant amounts of cured
material 305. This reduces and simplifies the cost of the entire process. Alternatively, the
25 material 305 may be used during this phase of the process.
Once the interior region 3 10 becomes sufficiently pressurized, the tubular member
210 is extruded off of the expandable mandrel 205. During the extrusion process, the
expandable mandrel 205 may be raised out of the expanded portion of the tubular member
210. In a preferred embodiment, during the extrusion process, the mandrel 205 is raised
30 at approximately the same rate as the tubular member 2 1 0 is expanded in order to keep the
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tubular member 2 1 0 stationary relative to the new wellbore section 130. In an alternative
preferred embodiment, the extrusion process is commenced with the tubular member 2 1 0
positioned above the bottom of the new wellbore section 130, keeping the mandrel 205
stationary, and allowing the tubular member 2 1 0 to extrude offof the mandrel 205 and fall
5 down the new wellbore section 130 under the force of gravity.
The plug 405 is preferably placed into the fluid passage 240 by introducing the
plug 405 into the fluid passage 230 at a surface location in a conventional manner. The
plug 405 preferably acts to fluidicly isolate the hardenable fluidic sealing material 305
from the non hardenable fluidic material 306.
10 The plug 405 may comprise any number of conventional commercially available
devices from plugging a fluid passage such as, for example, Multiple Stage Cementer
(MSG) latch-down plug, Omega latch-down plug or three-wiper latch-down plugmodified
in accordance with the teachings of the present disclosure. In a preferred embodiment, the
plug 405 comprises a MSC latch-down plug available from Halliburton Energy Services
15 in Dallas, TX.
After placement of the plug 405 in the fluid passage 240, a non hardenable fluidic
material 306 is preferably pumped into the interior region 3 10 at pressures and flow rates
ranging, for example, from approximately 400 to 10,000 psi and 30 to 4,000 gallons/min
(27.58 to 689.476 bar and 113.56 to 15141.68 litres/minute). In this manner, the amount
20 of hardenable fluidic sealing material within the interior 310 of the tubular member 210
is minimized. In a preferred embodiment, after placement of the plug 405 in the fluid
passage 240, the non hardenable material 306 is preferably pumped into the interior region
310 at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to
3,000 gallons/min (34.47 to 620.53 bar and 151 .42 to 1 1356.24 litres/minute) in order to
25 maximize the extrusion speed.
In apreferred embodiment, the apparatus 200 is adapted to minimize tensile, burst,
and friction effects upon the tubular member 210 during the expansion process. These
effects will depend upon the geometry of the expansion mandrel 205, the material
composition of the tubular member 210 and expansion mandrel 205, the inner diameter
30 of the tubular member 210, the wall thickness of the tubular member 210, the type of
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lubricant, and the yield strength of the tubular member 210. In general, the thicker the
wall thickness, the smaller the inner diameter, and the greater the yield strength of the
tubular member 210, then the greater the operating pressures required to extrude the
tubular member 210 off of the mandrel 205.
5 For typical tubular members 2 1 0, the extrusion of the tubular member 2 1 0 off of
the expandable mandrel will begin when the pressure of the interior region 3 10 reaches,
for example, approximately (34.47 to 620.53 bar).
During the extrusion process, the expandable mandrel 205 may be raised out of the
expanded portion of the tubular member 210 at rates ranging, for example, from about 0
10 to 5 ft/sec (0 to 1.524 metres). In a preferred embodiment, during the extrusion process,
the expandable mandrel 205 is raised out of the expanded portion of the tubular member
2 i 0 at rates ranging from about 0 to 2 ft/sec (0 to 0.6096 metres) in order to minimize the
time required for the expansion process while also permitting easy control of the
expansion process.
15 When the end portion 260 of the tubular member 210 is extruded off of the
expandable mandrel 205, the outer surface 265 of the end portion 260 of the tubular
member 210 will preferably contact the interior surface 410 of the end portion 270 of the
casing 115 to form an fluid tight overlapping joint. The contact pressure of the
overlapping joint may range, for example, from approximately 50 to 20,000 psi (3.447 to
20 137.95 bar). In a preferred embodiment, the contact pressure of the overlapping joint
ranges from approximately 400 to 10,000 psi (27.58 to 689.476 bar) in order to provide
optimum pressure to activate the annular sealing members 245 and optimally provide
resistance to axial motion to accommodate typical tensile and compressive loads.
The overlapping joint between the section 410 of the existing casing 1 15 and the
25 section 265 of the expanded tubular member 2 1 0 preferably provides a gaseous and fluidic
seal. In a particularly preferred embodiment, the sealing members 245 optimally provide
a fluidic and gaseous seal in the overlapping joint.
In a preferred embodiment, the operating pressure and flow rate of the non
hardenable fluidic material 306 is controllably ramped down when the expandable
30 mandrel 205 reaches the end portion 260 of the tubular member 2 10. In this manner, the
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sudden release of pressure caused by the complete extrusion of the tubular member 210
off of the expandable mandrel 205 can be minimized. In a preferred embodiment, the
operating pressure is reduced in a substantially linear fashion from 100% to about 10%
during the end of the extrusion process beginning when the mandrel 205 is within about
5 5 feet ( 1 .524 metres) from completion of the extrusion process.
Alternatively, or in combination, a shock absorber is provided in the support
member 250 in order to absorb the shock caused by the sudden release of pressure. The
shock absorber may comprise, for example, any conventional commercially available
shock absorber adapted for use in wellbore operations.
10 Alternatively, or in combination, a mandrel catching structure is provided in the
end portion 260 of the tubular member 210 in order to catch or at least decelerate the
mandrel 205.
Once the extrusion process is completed, the expandable mandrel 205 is removed
from the wellbore 100. In a preferred embodiment, either before or after the removal of
15 the expandable mandrel 205, the integrity of the fluidic seal of the overlapping joint
between the upper portion 260 of the tubular member 210 and the lower portion 270 of
the casing 1 15 is tested using conventional methods.
If the fluidic seal of the overlapping joint between the upper portion 260 of the
tubular member 210 and the lower portion 270 of the casing 1 15 is satisfactory, then any
20 uncured portion of the material 305 within the expanded tubular member 210 is then
removed in a conventional manner such as, for example, circulating the uncured material
out of the interior of the expanded tubular member 210. The mandrel 205 is then pulled
out of the wellbore section 130 and a drill bit or mill is used in combination with a
conventional drilling assembly 505 to drill out any hardened material 305 within the
25 tubular member 2 1 0. The material 305 within the annular region 3 1 5 is then allowed to
cure.
As illustrated in Fig. 5, preferably any remaining cured material 305 within the
interior of the expanded tubular member 210 is then removed in a conventional manner
using a conventional drill string 505. The resulting new section of casing 5 10 includes the
30 expanded tubular member 2 1 0 and an outer annular layer 5 1 5 of cured material 305 . The
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bottom portion of the apparatus 200 comprising the shoe 215 and dart 405 may then be
removed by drilling out the shoe 215 and dart 405 using conventional drilling methods.
In a preferred embodiment, as illustrated in Fig. 6, the upper portion 260 of the
tubular member 2 1 0 includes one or more sealing members 605 and one or more pressure
5 relief holes 610. In this manner, the overlapping joint between the lower portion 270 of
the casing 1 1 5 and the upper portion 260 of the tubular member 2 1 0 is pressure-tight and
the pressure on the interior and exterior surfaces of the tubular member 2 1 0 is equalized
during the extrusion process.
In apreferred embodiment, the sealing members 605 are seated within recesses 61 5
10 formed in the outer surface 265 of the upper portion 260 of the tubular member 210. In
an alternative preferred embodiment, the sealing members 605 are bonded or molded onto
the outer surface 265 of the upper portion 260 of the tubular member 210. The pressure
relief holes 610 are preferably positioned in the last few feet of the tubular member 210.
The pressure relief holes reduce the operating pressures required to expand the upper
15 portion 260 of the tubular member 2 1 0. This reduction in required operating pressure in
turn reduces the velocity of the mandrel 205 upon the completion of the extrusion process.
This reduction in velocity in turn minimizes the mechanical shock to the entire apparatus
200 upon the completion of the extrusion process.
Referring now to Fig. 7, a particularly preferred embodiment of an apparatus 700
20 for forming a casing within a wellbore preferably includes an expandable mandrel or pig
705, an expandable mandrel or pig container 7 1 0, a tubular member 7 1 5 , a float shoe 720,
a lower cup seal 725, an upper cup seal 730, a fluid passage 735, a fluid passage 740, a
support member 745, a body of lubricant 750, an overshot connection 755, another support
member 760, and a stabilizer 765.
25 The expandable mandrel 705 is coupled to and supported by the support member
745. The expandable mandrel 705 is further coupled to the expandable mandrel container
7 1 0. The expandable mandrel 705 is preferably adapted to controllably expand in a radial
direction. The expandable mandrel 705 may comprise any number of conventional
commercially available expandable mandrels modified in accordance with the teachings
30 of the present disclosure. In a preferred embodiment, the expandable mandrel 705
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comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5 ,348,095 ,
the contents of which are incorporated herein by reference, modified in accordance with
the teachings of the present disclosure.
The expandable mandrel container 7 1 0 is coupled to and supported by the support
5 member 745. The expandable mandrel container 7 1 0 is further coupled to the expandable
mandrel 705. The expandable mandrel container 710 may be constructed from any
number of conventional commercially available materials such as, for example, Oilfield
Country Tubular Goods, stainless steel, titanium or high strength steels. In a preferred
embodiment, the expandable mandrel container 710 is fabricated from material having a
10 greater strength than the material from which the tubular member 7 1 5 is fabricated. In this
manner, the container 710 can be fabricated from a tubular material having a thinner wall
thickness than the tubular member 210. This permits the container 710 to pass through
tight clearances thereby facilitating its placement within the wellbore.
In a preferred embodiment, once the expansion process begins, and the thicker,
15 lower strength material of the tubular member 715 is expanded, the outside diameter of
the tubular member 7 1 5 is greater than the outside diameter of the container 710.
The tubular member 71 5 is coupled to and supported by the expandable mandrel
705. The tubular member 715 is preferably expanded in the radial direction and extruded
off of the expandable mandrel 705 substantially as described above with reference to Figs.
20 1-6. The tubular member 715 may be fabricated from any number of materials such as,
for example, Oilfield Country Tubular Goods (OCTG), automotive grade steel or plastics.
In a preferred embodiment, the tubular member 715 is fabricated from OCTG.
In a preferred embodiment, the tubular member 715 has a substantially annular
cross-section. In a particularly preferred embodiment, the tubular member 715 has a
25 substantially circular annular cross-section.
The tubular member 715 preferably includes an upper section 805, an intermediate
section 810, and a lower section 815. The upper section 805 of the tubular member 715
preferably is defined by the region beginning in the vicinity of the mandrel container 710
and ending with the top section 820 of the tubular member 715. The intermediate section
30 810 f the tubular member 715 is preferably defined by the region beginning in the
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vicinity of the top of the mandrel container 7 1 0 and ending with the region in the vicinity
of the mandrel 705. The lower section of the tubular member 715 is preferably defined
by the region beginning in the vicinity of the mandrel 705 and ending at the bottom 825
of the tubular member 715.
5 In a preferred embodiment, the wall thickness of the upper section 805 of the
tubular member 715 is greater than the wall thicknesses of the intermediate and lower
sections 810 and 815 of the tubular member 715 in order to optimally faciliate the
initiation of the extrusion process and optimally permit the apparatus 700 to be positioned
in locations in the wellbore having tight clearances.
10 The outer diameter and wall thickness of the upper section 805 of the tubular
member 715 may range, for example, from about 1.05 to 48 inches and 1/8 to 2 inches
(2.667 to 121.92 and 0.3175 to 5.08 centimetres), respectively. In a preferred
embodiment, the outer diameter and wall thickness of the upper section 805 of the tubular
member 715 range from about 3.5 to 16 inches and 3/8 to 1.5 inches (8.89 to 40.64
15 centimetres and 0.9525 to 3.81 centimetres), respectively.
The outer diameter and wall thickness of the intermediate section 8 1 0 of the tubular
member 715 may range, for example, from about 2.5 to 50 inches and 1/16 to 1,5 inches
(6.35 to 127 centimetres and 0.159 to 3.81 centimetres), respectively. In a preferred
embodiment, the outer diameter and wall thickness of the intermediate section 8 1 0 of the
20 tubular member 715 range from about 3.5 to 19 inches and 1/8 to 1.25 inches (8.89 to
48.26 and 0.3175 to 3.175 centimetres), respectively.
The outer diameter and wall thickness of the lower section 815 of the tubular
member 715 may range, for example, from about 2.5 to 50 inches and 1/16 to 1 .25 inches
(6.35 to 127 centimetres and 0.159 to 3.175 centimetres), respectively. In a preferred
25 embodiment, the outer diameter and wall thickness of the lower section 8 1 0 of the tubular
member 715 range from about 3.5 to 19 inches and 1/8 to 1.25 inches (8.89 to 48.26 and
0.3175 to 3. 175 centimetres), respectively. In a particularly preferred embodiment, the
wall thickness of the lower section 8 1 5 of the tubular member 7 1 5 is further increased to
increase the strength of the shoe 720 when (billable materials such as, for example,
30 aluminum are used. The tubular member 715 preferably comprises a solid tubular
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member. In a preferred embodiment, the end portion 820 of the tubular member 715 is
slotted, perforated, or otherwise modified to catch or slow down the mandrel 705 when
it completes the extrusion of tubular member 715. In a preferred embodiment, the length
of the tubular member 715 is limited to minimize the possibility of buckling. For typical
5 tubular member 7 1 5 materials, the length of the tubular member 7 1 5 is preferably limited
to between about 40 to 20,000 feet (12. 192 to 6096.00 metres) in length.
The shoe 720 is coupled to the expandable mandrel 705 and the tubular member
715. The shoe 720 includes the fluid passage 740. In a preferred embodiment, the shoe
720 further includes an inlet passage 830, and one or more jet ports 835. In a particularly
10 preferred embodiment, the cross-sectional shape of the inlet passage 830 is adapted to
receive a latch-down dart, or other similar elements, for blocking the inlet passage 830.
The interior of the shoe 720 preferably includes a body of solid material 840 for increasing
the strength of the shoe 720. In a particularly preferred embodiment, the body of solid
material 840 comprises aluminum.
15 The shoe 720 may comprise any number of conventional commercially available
shoes such as, for example, Super Seal II Down-Jet float shoe, or guide shoe with a sealing
sleeve for a latch down plug modified in accordance with the teachings of the present
disclosure. In a preferred embodiment, the shoe 720 comprises an aluminum down-jet
guide shoe with a sealing sleeve for a latch-down plug available from Halliburton Energy
20 Services in Dallas, TX, modified in accordance with the teachings of the present
disclosure, in order to optimize guiding the tubular member 7 1 5 in the wellbore, optimize
the seal between the tubular member 7 1 5 and an existing wellbore casing, and to optimally
faciliate the removal of the shoe 720 by drilling it out after completion of the extrusion
process.
25 The lower cup seal 725 is coupled to and supported by the support member 745.
The lower cup seal 725 prevents foreign materials from entering the interior region of the
tubular member 715 above the expandable mandrel 705. The lower cup seal 725 may
comprise any number of conventional commercially available cup seals such as, for
example, TP cups or Selective Injection Packer (SIP) cups modified in accordance with
30 the teachings of the present disclosure. In a preferred embodiment, the lower cup seal 725
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comprises a SIP cup, available from Halliburton Energy Services in Dallas, TX in order
to optimally provide a debris barrier and hold a body of lubricant.
The upper cup seal 730 is coupled to and supported by the support member 760.
The upper cup seal 730 prevents foreign materials from entering the interior region of the
5 tubular member 715. The upper cup seal 730 may comprise any number of conventional
commercially available cup seals such as, for example, TP cups or Selective Injection
Packer (SIP) cup modified in accordance with the teachings of the present disclosure. In
a preferred embodiment, the upper cup seal 730 comprises a SIP cup available from
Halliburton Energy Services in Dallas, TX in order to optimally provide a debris barrier
10 and contain a body of lubricant.
The fluid passage 735 permits fluidic materials to be transported to and from the
interior region of the tubular member 7 1 5 below the expandable mandrel 705. The fluid
passage 735 is fluidicly coupled to the fluid passage 740. The fluid passage 735 is
preferably coupled to and positioned within the support member 760, the support member
15 745, the mandrel container 7 1 0, and the expandable mandrel 705 . The fluid passage 735
preferably extends from a position adjacent to the surface to the bottom of the expandable
mandrel 705. The fluid passage 735 is preferably positioned along a centerline of the
apparatus 700. The fluid passage 735 is preferably selected to transport materials such as
cement, drilling mud or epoxies at flow rates and pressures ranging from about 40 to 3,000
20 gallons/minute and (34.47 to 620.53 bar) in order to optimally provide sufficient operating
pressures to extrude the tubular member 715 off of the expandable mandrel 705.
As described above with reference to Figs. 1 -6, during placement of the apparatus
700 within a new section of a wellbore, fluidic materials forced up the fluid passage 735
can be released into the wellbore above the tubular member 715. In a preferred
25 embodiment, the apparatus 700 further includes a pressure release passage that is coupled
to and positioned within the support member 260. The pressure release passage is further
fluidicly coupled to the fluid passage 735. The pressure release passage preferably
includes a control valve for controllably opening and closing the fluid passage. In a
preferred embodiment, the control valve is pressure activated in order to controllably
30 minimize surge pressures. The pressure release passage is preferably positioned
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substantially orthogonal to the centerline of the apparatus 700. The pressure release
passage is preferably selected to convey materials such as cement, drilling mud or epoxies
at flow rates and pressures ranging from about 0 to 500 gallons/minute and 0 to 1 ,000 psi
(0 to 1892.705 litres/minute and 0 to 68.95 bar) in order to reduce the drag on the
5 apparatus 700 during insertion into a new section of a wellbore and to minimize surge
pressures on the new wellbore section.
The fluid passage 740 permits fluidic materials to be transported to and from the
region exterior to the tubular member 715. The fluid passage 740 is preferably coupled
to and positioned within the shoe 720 in fluidic communication with the interior region
10 of the tubular member 715 below the expandable mandrel 705. The fluid passage 740
preferably has a cross-sectional shape that permits a plug; or other similar device, to be
placed in the inlet 830 of the fluid passage 740 to thereby block further passage of fluidic
materials. In this manner, the interior region of the tubular member 715 below the
expandable mandrel 705 can be optimally fluidicly isolated from the region exterior to the
15 tubular member 715. This permits the interior region of the tubular member 715 below
the expandable mandrel 205 to be pressurized.
The fluid passage 740 is preferably positioned substantially along the centerline
of the apparatus 700. The fluid passage 740 is preferably selected to convey materials
such as cement, drilling mud or epoxies at flow rates and pressures ranging from about 0
20 to 3,000 gallons/minute and 0 to 9,000 psi (0 to 1 1356.24 litres/minute/minute and 0 to
620.528 bar) in order to optimally fill an annular region between the tubular member 715
and a new section of a wellbore with fluidic materials. In a preferred embodiment, the
fluid passage 740 includes an inlet passage 830 having a geometry that can receive a dart
and/or a ball sealing member. In this manner, the fluid passage 240 can be sealed offby
25 introducing a plug, dart and/or ball sealing elements into the fluid passage 230.
In a preferred embodiment, the apparatus 700 further includes one or more seals
845 coupled to and supported by the end portion 820 of the tubular member 715, The
seals 845 are further positioned on an outer surface of the end portion 820 of the tubular
member 715. The seals 845 permit the overlapping joint between an end portion of
30 preexisting casing and the end portion 820 of the tubular member 715 to be fluidicly
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sealed. The seals 845 may comprise any number of conventional commercially available
seals such as, for example, lead, rubber, Teflon (RTM), or epoxy seals modified in
accordance with the teachings of the present disclosure. In a preferred embodiment, the
seals 845 comprise seals molded from StrataLock epoxy available from Halliburton
5 Energy Services in Dallas, TX in order to optimally provide a hydraulic seal and a load
bearing interference fit in the overlapping joint between the tubular member 715 and an
existing casing with optimal load bearing capacity to support the tubular member 715.
In a preferred embodiment, the seals 845 are selected to provide a sufficient
frictional force to support the expanded tubular member 7 1 5 from the existing casing. In
10 a preferred embodiment, the frictional force provided by the seals 845 ranges from about
1,000 to 1,000,000 Ibf (0.478803 to 478.803 bar) in order to optimally support the
expanded tubular member 7 1 5.
The support member 745 is preferably coupled to the expandable mandrel 705 and
the overshot connection 755. The support member 745 preferably comprises an annular
15 member having sufficient strength to cany the apparatus 700 into a new section of a
wellbore. The support member 745 may comprise any number of conventional
commercially available support members such as, for example, steel drill pipe, coiled
tubing or other high strength tubular modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the support member 745 comprises
20 conventional drill pipe available from various steel mills in the United States.
In a preferred embodiment, a body of lubricant 750 is provided in the annular
region above the expandable mandrel container 710 within the interior of the tubular
member 715. In this manner, the extrusion of the tubular member 715 off of the
expandable mandrel 705 is facilitated. The lubricant 705 may comprise any number of
25 conventional commercially available lubricants such as, for example, Lubriplate (RTM),
chlorine based lubricants, oil based lubricants, or Climax 1500 Antisieze (3100). In a
preferred embodiment, the lubricant 750 comprises Climax 1500 Antisieze (3100)
available from Halliburton Energy Services in Houston, TX in order to optimally provide
lubrication to faciliate the extrusion process.
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The overshot connection 75 5 is coupled to the support member 745 and the support
member 760. The overshot connection 755 preferably permits the support member 745
to be removably coupled to the support member 760. The overshot connection 755 may
comprise any number of conventional commercially available overshot connections such
5 as, for example, Innerstring Sealing Adapter, Innerstring Flat-Face Sealing Adapter or EZ
Drill Setting Tool Stinger. In a preferred embodiment, the overshot connection 755
comprises a Innerstring Adapter with an Upper Guide available from Halliburton Energy
Services in Dallas, TX.
The support member 760 is preferably coupled to the overshot connection 755 and
10 a surface support structure (not illustrated). The support member 760 preferably
comprises an annular member having sufficient strength to carry the apparatus 700 into
a new section of a wellbore. The support member 760 may comprise any number of
conventional commercially available support members such as, for example, steel drill
pipe, coiled tubing or other high strength tubulars modified in accordance with the
15 teachings of the present disclosure. In a preferred embodiment, the support member 760
comprises a conventional drill pipe available from steel mills in the United States.
The stabilizer 765 is preferably coupled to the support member 760. The stabilizer
765 also preferably stabilizes the components of the apparatus 700 within the tubular
member 715. The stabilizer 765 preferably comprises a spherical member having an
20 outside diameter that is about 80 to 99% of the interior diameter of the tubular member
715 in order to optimally minimize buckling of the tubular member 715. The stabilizer
765 may comprise any number of conventional commercially available stabilizers such
as, for example, EZ Drill Star Guides, packer shoes or drag blocks modified in accordance
with the teachings of the present disclosure. In a preferred embodiment, the stabilizer 765
25 comprises a sealing adapter upper guide available from Halliburton Energy Services in
Dallas, TX.
In a preferred embodiment, the support members 745 and 760 are thoroughly
cleaned prior to assembly to the remaining portions of the apparatus 700. In this manner,
the introduction of foreign material into the apparatus 700 is minimized. This minimizes
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the possibility of foreign material clogging the various flow passages and valves of the
apparatus 700.
In a preferred embodiment, before or after positioning the apparatus 700 within a
new section of a wellbore, a couple of wellbore volumes are circulated through the various
5 flow passages of the apparatus 700 in order to ensure that no foreign materials are located
within the wellbore that might clog up the various flow passages and valves of the
apparatus 700 and to ensure that no foreign material interferes with the expansion mandrel
705 during the expansion process.
In a preferred embodiment, the apparatus 700 is operated substantially as described
10 above with reference to Figs. 1-7 to form a new section of casing within a wellbore.
As illustrated in Fig. 8, in an alternative preferred embodiment, the method and
apparatus described herein is used to repair an existing wellbore casing 80S by forming
a tubular liner 8 1 0 inside of the existing wellbore casing 805. In a preferred embodiment,
an outer annular lining of cement is not provided in the repaired section. In the alternative
15 preferred embodiment, any number of fluidic materials can be used to expand the tubular
liner 810 into intimate contact with the damaged section of the wellbore casing such as,
for example, cement, epoxy, slag mix, or drilling mud. In the alternative preferred
embodiment, sealing members 815 are preferably provided at both ends of the tubular
member in order to optimally provide a fluidic seal. In an alternative preferred
20 embodiment, the tubular liner 810 is formed within a horizontally positioned pipeline
section, such as those used to transport hydrocarbons or water, with the tubular liner 810
placed in an overlapping relationship with the adjacent pipeline section. In this manner,
underground pipelines can be repaired without having to dig out and replace the damaged
sections.
25 In another alternative preferred embodiment, the method and apparatus described
herein is used to directly line a wellbore with a tubular liner 810. In a preferred
embodiment, an outer annular lining of cement is not provided between the tubular liner
8 1 0 and the wellbore. In the alternative preferred embodiment, any number of fluidic
materials can be used to expand the tubular liner 810 into intimate contact with the
30 wellbore such as, for example, cement, epoxy, slag mix, or drilling mud.
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Referring now to Figs. 9, 9a, 9b and 9c, a preferred embodiment of an apparatus
900 for forming a wellbore casing includes an expandible tubular member 902, a support
member 904, an expandible mandrel or pig 906, and a shoe 908. In a preferred
embodiment, the design and construction of the mandrel 906 and shoe 908 permits easy
5 removal of those elements by drilling them out In this manner, the assembly 900 can be
easily removed from a wellbore using a conventional drilling apparatus and corresponding
drilling methods.
The expandible tubular member 902 preferably includes an upper portion 9 10, an
intermediate portion 9 12 and a lower portion 914. During operation of the apparatus 900,
10 the tubular member 902 is preferably extruded off of the mandrel 906 by pressurizing an
interior region 966 of the tubular member 902. The tubular member 902 preferably has
a substantially annular cross-section.
In a particularly preferred embodiment, an expandable tubular member 915 is
coupled to the upper portion 910 of the expandable tubular member 902. During
1 5 operation of the apparatus 900, the tubular member 9 1 5 is preferably extruded off of the
mandrel 906 by pressurizing the interior region 966 of the tubular member 902. The
tubular member 9 15 preferably has a substantially annular cross-section. In a preferred
embodiment, the wall thickness of the tubular member 915 is greater than the wall
thickness of the tubular member 902.
20 The tubular member 915 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low alloy steels,
titanium or stainless steels. In a preferred embodiment, the tubular member 915 is
fabricated from oilfield tubulars in order to optimally provide approximately the same
mechanical properties as the tubular member 902. In a particularly preferred embodiment,
25 thetubularmember915hasaplasticyieldpointrangingfromabout40,000to 135,000psi
(2757.90 to 9307.92 bar) in order to optimally provide approximately the same yield
properties as the tubular member 902. The tubular member 915 may comprise a plurality
of tubular members coupled end to end.
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In a preferred embodiment, the upper end portion of the tubular member 915
includes one or more sealing members for optimally providing a fluidic and/or gaseous
seal with an existing section of wellbore casing.
In a preferred embodiment, the combined length of the tubular members 902 and
5 915 are limited to minimize the possibility of buckling. For typical tubular member
materials, the combined length of the tubular members 902 and 9 1 5 are limited to between
about 40 to 20,000 feet (12.192 to 6096.00 metres) in length.
The lower portion 9 1 4 of the tubular member 902 is preferably coupled to the shoe
908 by a threaded connection 968, The intermediate portion 9 1 2 of the tubular member
10 902 preferably is placed in intimate sliding contact with the mandrel 906.
The tubular member 902 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low alloy steels,
titanium or stainless steels. In a preferred embodiment, the tubular member 902 is
fabricated from oilfield tubulars in order to optimally provide approximately the same
15 mechanical properties as the tubular member 915. In a particularly preferred embodiment,
the tubular member 902 has a plastic yield point ranging from about 40,000 to 135,000 psi
(2757.90 to 9307.92 bar) in order to optimally provide approximately the same yield
properties as the tubular member 915.
The wall thickness of the upper, intermediate, and lower portions, 910, 912 and
20 914 of the tubular member 902 may range, for example, from about 1/16 to 1.5 inches
(0.159 to 3.81 centimetres). In a preferred embodiment, the wall thickness of the upper,
intermediate, and lower portions, 9 1 0, 9 1 2 and 9 1 4 of the tubular member 902 range from
about 1/8 to 1.25 inches (0.3175 to 3.175 centimetres) order to optimally provide wall
thickness that are about the same as the tubular member 915. In a preferred embodiment,
25 the wall thickness of the lower portion 914 is less than or equal to the wall thickness of
the upper portion 910 in order to optimally provide a geometry that will fit into tight
clearances downhole.
The outer diameter of the upper, intermediate, and lower portions, 910, 912 and
914 of the tubular member 902 may range, for example, from about 1.05 to 48 inches
30 (2.667 to 1 2 1 .92 centimetres). In apreferred embodiment, the outer diameter of the upper,
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intermediate, and lower portions, 910,912 and 9 1 4 of the tubular member 902 range from
about 3 V4 to 1 9 inches (8.89 to 48.26 centimetres) in order to optimally provide the ability
to expand the most commonly used oilfield tubulars.
The length of the tubular member 902 is preferably limited to between about 2 to
5 5 feet (1.524 metres) in order to optimally provide enough length to contain the mandrel
906 and a body of lubricant.
The tubular member 902 may comprise any number of conventional commercially
available tubular members modified in accordance with the teachings of the present
disclosure. In a preferred embodiment, the tubular member 902 comprises Oilfield
10 Country Tubular Goods available from various U.S. steel mills. The tubular member 915
may comprise any number of conventional commercially available tubular members
modified in accordance with the teachings of the present disclosure. In a preferred
embodiment, the tubular member 915 comprises Oilfield Country Tubular Goods available
from various U.S. steel mills.
1 5 The various elements of the tubular member 902 may be coupled using any number
of conventional process such as, for example, threaded connections, welding or machined
from one piece. In a preferred embodiment, the various elements of the tubular member
902 are coupled using welding. The tubular member 902 may comprise a plurality of
tubular elements that are coupled end to end. The various elements of the tubular member
20 915 may be coupled using any number of conventional process such as, for example,
threaded connections, welding or machined from one piece. In a preferred embodiment,
the various elements of the tubular member 9 1 5 are coupled using welding. The tubular
member 915 may comprise a plurality of tubular elements that are coupled end to end.
The tubular members 902 and 915 may be coupled using any number of conventional
25 process such as, for example, threaded connections, welding or machined from one piece.
The support member 904 preferably includes an innerstring adapter 916, a fluid
passage 918, an upper guide 920, and a coupling 922. During operation of the apparatus
900, the support member 904 preferably supports the apparatus 900 during movement of
the apparatus 900 within a wellbore. The support member 904 preferably has a
30 substantially annular cross-section.
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The support member 904 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low alloy steel,
coiled tubing or stainless steel. In a preferred embodiment, the support member 904 is
fabricated from low alloy steel in order to optimally provide high yield strength.
5 The innerstring adaptor 916 preferably is coupled to and supported by a
conventional drill string support from a surface location. The innerstring adaptor 916 may
be coupled to a conventional drill string support 971 by a threaded connection 970.
The fluid passage 9 1 8 is preferably used to convey fluids and other materials to and
from the apparatus 900. In a preferred embodiment, the fluid passage 918 is fluidicly
10 coupled to the fluid passage 952 . In a preferred embodiment, the fluid passage 9 1 8 is used
to convey hardenable fluidic sealing materials to and from the apparatus 900. In a
particularly preferred embodiment, the fluid passage 918 may include one or more
pressure relief passages (not illustrated) to release fluid pressure during positioning of the
apparatus 900 within a wellbore. In a preferred embodiment, the fluid passage 918 is
15 positioned along a longitudinal centerline of the apparatus 900. In a preferred
embodiment, the fluid passage 918 is selected to permit the conveyance of hardenable
fluidic materials at operating pressures ranging from about 0 to 9,000 psi (0 to 620.528
bar).
The upper guide 920 is coupled to an upper portion of the support member 904.
20 The upper guide 920 preferably is adapted to center the support member 904 within the
tubular member 915. The upper guide 920 may comprise any number of conventional
guide members modified in accordance with the teachings of the present disclosure. In
a preferred embodiment, the upper guide 920 comprises an innerstring adapter available
from Halliburton Energy Services in Dallas, TX order to optimally guide the apparatus
25 900 within the tubular member 915.
The coupling 922 couples the support member 904 to the mandrel 906. The
coupling 922 preferably comprises a conventional threaded connection.
The various elements of the support member 904 may be coupled using any
number of conventional processes such as, for example, welding, threaded connections or
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machined from one piece. In a preferred embodiment, the various elements of the support
member 904 are coupled using threaded connections.
The mandrel 906 preferably includes a retainer 924, a rubber cup 926, an
expansion cone 928, a lower cone retainer 930, a body of cement 932, a lower guide 934,
5 an extension sleeve 936, a spacer 938, a housing 940, a sealing sleeve 942, an upper cone
retainer 944, a lubricator mandrel 946, a lubricator sleeve 948, a guide 950, and a fluid
passage 952.
The retainer 924 is coupled to the lubricator mandrel 946, lubricator sleeve 948,
and the rubber cup 926. The retainer 924 couples the rubber cup 926 to the lubricator
10 sleeve 948. The retainer 924 preferably has a substantially annular cross-section. The
retainer 924 may comprise any number of conventional commercially available retainers
such as, for example, slotted spring pins or roll pin.
The rubber cup 926 is coupled to the retainer 924, the lubricator mandrel 946, and
the lubricator sleeve 948. The rubber cup 926 prevents the entry of foreign materials into
15 the interior region 972 of the tubular member 902 below the rubber cup 926. The rubber
cup 926 may comprise any number of conventional commercially available rubber cups
such as, for example, TP cups or Selective Injection Packer (SIP) cup. In a preferred
embodiment, the rubber cup 926 comprises a SIP cup available from Halliburton Energy
Services in Dallas, TX in order to optimally block foreign materials.
20 In a particularly preferred embodiment, a body of lubricant is further provided in
the interior region 972 of the tubular member 902 in order to lubricate the interface
between the exterior surface of the mandrel 902 and the interior surface of the tubular
members 902 and 915. The lubricant may comprise any number of conventional
commercially available lubricants such as, for example, Lubriplate (RTM), chlorine based
25 lubricants, oil based lubricants or Climax 1500 Antiseize (3100). In a preferred
embodiment, the lubricant comprises Climax 1500 Antiseize (3100) available from
Climax Lubricants and Equipment Co. in Houston, TX in order to optimally provide
lubrication to faciliate the extrusion process.
The expansion cone 928 is coupled to the lower cone retainer 930, the body of
30 cement 932, the lower guide 934, the extension sleeve 936, the housing 940, and the upper
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cone retainer 944. In a preferred embodiment, during operation of the apparatus 900, the
tubular members 902 and 915 are extruded off of the outer surface of the expansion cone
928. In a preferred embodiment, axial movement of the expansion cone 928 is prevented
by the lower cone retainer 930, housing 940 and the upper cone retainer 944. Inner radial
5 movement of the expansion cone 928 is prevented by the body of cement 932, the housing
940, and the upper cone retainer 944.
The expansion cone 928 preferably has a substantially annular cross section. The
outside diameter of the expansion cone 928 is preferably tapered to provide a cone shape.
The wall thickness of the expansion cone 928 may range, for example, from about 0. 125
10 to 3 inches (0.3175 to 7.62 centimetres). In a preferred embodiment, the wall thickness
of the expansion cone 928 ranges from about 0.25 to 0.75 inches (0.635 to 1.905
centimetres) in order to optimally provide adequate compressive strength with minimal
material. The maximum and minimum outside diameters of the expansion cone 928 may
range, for example, from about 1 to 47 inches (2.54 to 1 1 9.38 centimetres). In a preferred
15 embodiment, the maximum and minimum outside diameters of the expansion cone 928
range from about 3.5 to 19 in (8.89 to 48.26 centimetres) order to optimally provide
expansion of generally available oilfield tubulars
The expansion cone 928 may be fabricated from any number of conventional
commercially available materials such as, for example, ceramic, tool steel, titanium or low
20 alloy steel. In a preferred embodiment, the expansion cone 928 is fabricated from tool
steel in order to optimally provide high strength and abrasion resistance. The surface
hardness of the outer surface of the expansion cone 928 may range, for example, from
about 50 Rockwell C to 70 Rockwell C In a preferred embodiment, the surface hardness
of the outer surface of the expansion cone 928 ranges from about 58 Rockwell C to 62
25 Rockwell C in order to optimally provide high yield strength. In a preferred embodiment,
the expansion cone 928 is heat treated to optimally provide a hard outer surface and a
resilient interior body in order to optimally provide abrasion resistance and fracture
toughness.
The lower cone retainer 930 is coupled to the expansion cone 928 and the housing
30 940. In a preferred embodiment, axial movement of the expansion cone 928 is prevented
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by the lower cone retainer 930. Preferably, the lower cone retainer 930 has a substantially
annular cross-section.
The lower cone retainer 930 may be fabricated from any number of conventional
commercially available materials such as, for example, ceramic, tool steel, titanium or low
5 alloy steel. In a preferred embodiment, the lower cone retainer 93 0 is fabricated from tool
steel in order to optimally provide high strength and abrasion resistance. The surface
hardness of the outer surface of the lower cone retainer 930 may range, for example, from
about 50 Rockwell C to 70 Rockwell C. In a preferred embodiment, the surface hardness
of the outer surface of the lower cone retainer 930 ranges from about 58 Rockwell C to
10 62 Rockwell C in order to optimally provide high yield strength. In a preferred
embodiment, the lower cone retainer 930 is heat treated to optimally provide a hard outer
surface and a resilient interior body in order to optimally provide abrasion resistance and
fracture toughness.
In a preferred embodiment, the lower cone retainer 930 and the expansion cone 928
15 are formed as an integral one-piece element in order reduce the number of components
and increase the overall strength of the apparatus. The outer surface of the lower cone
retainer 930 preferably mates with the inner surfaces of the tubular members 902 and 9 1 5.
The body of cement 932 is positioned within the interior of the mandrel 906. The
body of cement 932 provides an inner bearing structure for the mandrel 906. The body
20 of cement 932 further may be easily drilled out using a conventional drill device. In this
manner, the mandrel 906 may be easily removed using a conventional drilling device.
The body of cement 932 may comprise any number of conventional commercially
available cement compounds. Alternatively, aluminum, cast iron or some other drillable
metallic, composite, or aggregate material may be substituted for cement The body of
25 cement 932 preferably has a substantially annular cross-section.
The lower guide 934 is coupled to the extension sleeve 936 and housing 940.
During operation of the apparatus 900, the lower guide 934 preferably helps guide the
movement of the mandrel 906 within the tubular member 902. The lower guide 934
preferably has a substantially annular cross-section.
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The lower guide 934 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low alloy steel
or stainless steel. In a preferred embodiment, the lower guide 934 is fabricated from low
alloy steel in order to optimally provide high yield strength. The outer surface of the
5 lower guide 934 preferably mates with the inner surface of the tubular member 902 to
provide a sliding fit.
The extension sleeve 936 is coupled to the lower guide 934 and the housing 940.
During operation of the apparatus 900, the extension sleeve 936 preferably helps guide the
movement of the mandrel 906 within the tubular member 902. The extension sleeve 936
10 preferably has a substantially annular cross-section.
The extension sleeve 936 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low alloy steel
or stainless steel. In a preferred embodiment, the extension sleeve 936 is fabricated from
low alloy steel in order to optimally provide high yield strength. The outer surface of the
15 extension sleeve 936 preferably mates with the inner surface of the tubular member 902
to provide a sliding fit. In a preferred embodiment, the extension sleeve 936 and the lower
guide 934 are formed as an integral one-piece element in order to minimize the number
of components and increase the strength of the apparatus.
The spacer 938 is coupled to the sealing sleeve 942. The spacer 938 preferably
20 includes the fluid passage 952 and is adapted to mate with the extension tube 960 of the
shoe 908. In this manner, a plug or dart can be conveyed from the surface through the
fluid passages 91 8 and 952 into the fluid passage 962. Preferably, the spacer 938 has a
substantially annular cross-section.
The spacer 93 8 may be fabricated from any number of conventional commercially
25 available materials such as, for example, steel, aluminum or cast iron. In a preferred
embodiment, the spacer 938 is fabricated from aluminum in order to optimally provide
drillability. The end of the spacer 938 preferably mates with the end of the extension tube
960. In a preferred embodiment, the spacer 938 and the sealing sleeve 942 are formed
as an integral one-piece element in order to reduce the number of components and increase
30 the strength of the apparatus.
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The housing 940 is coupled to the lower guide 934, extension sleeve 936,
expansion cone 928, body of cement 932, and lower cone retainer 930. During operation
of the apparatus 900, the housing 940 preferably prevents inner radial motion of the
expansion cone 928. Preferably, the housing 940 has a substantially annular cross-section.
5 The housing 940 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield tubulars, low alloy steel or stainless steel.
In a preferred embodiment, the housing 940 is fabricated from low alloy steel in order to
optimally provide high yield strength. In a preferred embodiment, the lower guide 934,
extension sleeve 936 and housing 940 are formed as an integral one-piece element in order
10 to minimize the number of components and increase the strength of the apparatus.
In a particularly preferred embodiment, the interior surface of the housing 940
includes one or more protrusions to faciliate the connection between the housing 940 and
the body of cement 932.
The sealing sleeve 942 is coupled to the support member 904, the body of cement
15 932, the spacer 938, and the upper cone retainer 944. During operation of the apparatus,
the sealing sleeve 942 preferably provides support for the mandrel 906. The sealing sleeve
942 is preferably coupled to the support member 904 using the coupling 922. Preferably,
the scaling sleeve 942 has a substantially annular cross-section.
The sealing sleeve 942 may be fabricated from any number of conventional
20 commercially available materials such as, for example, steel, aluminum or cast iron. In
a preferred embodiment, the sealing sleeve 942 is fabricated from aluminum in order to
optimally provide drillability of the sealing sleeve 942.
In a particularly preferred embodiment, the outer surface of the sealing sleeve 942
includes one or more protrusions to faciliate the connection between the sealing sleeve 942
25 and the body of cement 932.
In a particularly preferred embodiment, the spacer 938 and the sealing sleeve 942
are integrally formed as a one-piece element in order to minimize the number of
components.
The upper cone retainer 944 is coupled to the expansion cone 928, the sealing
30 sleeve 942, and the body of cement 932. During operation of the apparatus 900, the upper
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cone retainer 944 preferably prevents axial motion of the expansion cone 928. Preferably,
the upper cone retainer 944 has a substantially annular cross-section.
The upper cone retainer 944 may be fabricated from any number of conventional
commercially available materials such as, for example, steel, aluminum or cast iron. In
5 a preferred embodiment, the upper cone retainer 944 is fabricated from aluminum in order
to optimally provide drillability of the upper cone retainer 944.
In a particularly preferred embodiment, the upper cone retainer 944 has a cross-
sectional shape designed to provide increased rigidity. In a particularly preferred
embodiment, the upper cone retainer 944 has a cross-sectional shape that is substantially
10 I-shaped to provide increased rigidity and minimize the amount of material that would
have to be drilled out.
The lubricator mandrel 946 is coupled to the retainer 924, the rubber cup 926, the
upper cone retainer 944, the lubricator sleeve 948, and the guide 950. During operation
of the apparatus 900, the lubricator mandrel 946 preferably contains the body of lubricant
15 in the annular region 972 for lubricating the interface between the mandrel 906 and the
tubular member 902. Preferably, the lubricator mandrel 946 has a substantially annular
cross-section.
The lubricator mandrel 946 may be fabricated from any number of conventional
commercially available materials such as, for example, steel, aluminum or cast iron. In
20 a preferred embodiment, the lubricator mandrel 946 is fabricated from aluminum in order
to optimally provide drillability of the lubricator mandrel 946.
The lubricator sleeve 948 is coupled to the lubricator mandrel 946, the retainer 924,
the rubber cup 926, the upper cone retainer 944, the lubricator sleeve 948, and the guide
950. During operation of the apparatus 900, the lubricator sleeve 948 preferably supports
25 the rubber cup 926. Preferably, the lubricator sleeve 948 has a substantially annular cross-
section.
The lubricator sleeve 948 may be fabricated from any number of conventional
commercially available materials such as, for example, steel, aluminum or cast iron. In
a preferred embodiment, the lubricator sleeve 948 is fabricated from aluminum in order
30 to optimally provide drillability of the lubricator sleeve 948.
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As illustrated in Fig. 9c, the lubricator sleeve 948 is supported by the lubricator
mandrel 946. The lubricator sleeve 948 in turn supports the rubber cup 926. The retainer
924 couples the rubber cup 926 to the lubricator sleeve 948. In a preferred embodiment,
seals 949a and 949b are provided between the lubricator mandrel 946, lubricator sleeve
5 948, and rubber cup 926 in order to optimally seal off the interior region 972 of the tubular
member 902.
The guide 950 is coupled to the lubricator mandrel 946, the retainer 924, and the
lubricator sleeve 948. During operation of the apparatus 900, the guide 950 preferably
guides the apparatus on the support member 904. Preferably, the guide 950 has a
10 substantially annular cross-section.
The guide 950 may be fabricated from any number of conventional commercially
available materials such as, for example, steel, aluminum or cast iron. In a preferred
embodiment, the guide 950 is fabricated from aluminum order to optimally provide
drillability of the guide 950.
15 The fluid passage 952 is coupled to the mandrel 906. During operation of the
apparatus, the fluid passage 952 preferably conveys hardenable fluidic materials. In a
preferred embodiment, the fluid passage 952 is positioned about the centerline of the
apparatus 900. In a particularly preferred embodiment, the fluid passage 952 is adapted
to convey hardenable fluidic materials at pressures and flow rate ranging from about 0 to
20 9,000 psi and 0 to 3,000 gallons/min (0 to 620.528 bar and 0 to 1 1356.24 litres/minute)
in order to optimally provide pressures and flow rates to displace and circulate fluids
during the installation of the apparatus 900.
The various elements of the mandrel 906 may be coupled using any number of
conventional process such as, for example, threaded connections, welded connections or
25 cementing. In a preferred embodiment, the various elements of the mandrel 906 are
coupled using threaded connections and cementing.
The shoe 908 preferably includes a housing 954, a body of cement 956, a sealing
sleeve 958, an extension tube 960, a fluid passage 962, and one or more outlet jets 964.
The housing 954 is coupled to the body of cement 956 and the lower portion 91 4
30 of the tubular member 902. During operation of the apparatus 900, the housing 954
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preferably couples the lower portion of the tubular member 902 to the shoe 908 to
facilitate the extrusion and positioning of the tubular member 902. Preferably, the housing
954 has a substantially annular cross-section.
The housing 954 may be fabricated from any number of conventional commercially
5 available materials such as, for example, steel or aluminum. In a preferred embodiment,
the housing 954 is fabricated from aluminum in order to optimally provide drillability of
the housing 954.
In a particularly preferred embodiment, the interior surface of the housing 954
includes one or more protrusions to faciliate the connection between the body of cement
10 956 and the housing 954.
The body of cement 956 is coupled to the housing 954, and the sealing sleeve 958.
In a preferred embodiment, the composition of the body of cement 956 is selected to
permit the body of cement to be easily drilled out using conventional drilling machines
and processes.
15 The composition of the body of cement 956 may include any number of
conventional cement compositions. In an alternative embodiment, a drillable material
such as, for example, aluminum or iron may be substituted for the body of cement 956.
The sealing sleeve 958 is coupled to the body of cement 956, the extension tube
960, the fluid passage 962, and one or more outlet jets 964. During operation of the
20 apparatus 900, the sealing sleeve 958 preferably is adapted to convey a hardenable fluidic
material from the fluid passage 952 into the fluid passage 962 and then into the outlet jets
964 in order to inject the hardenable fluidic material into an annular region external to the
tubular member 902. In a preferred embodiment, during operation of the apparatus 900,
the sealing sleeve 958 further includes an inlet geometry that permits a conventional plug
25 or dart 974 to become lodged in the inlet of the sealing sleeve 958. In this manner, the
fluid passage 962 may be blocked thereby fluidicly isolating the interior region 966 of the
tubular member 902.
In apreferred embodiment, the sealing sleeve 958 has a substantially annular cross-
section. The sealing sleeve 958 may be fabricated from any number of conventional
30 commercially available materials such as, for example, steel, aluminum or cast iron. In
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a preferred embodiment, the sealing sleeve 958 is fabricated from aluminum in order to
optimally provide disability of the sealing sleeve 958.
The extension tube 960 is coupled to the sealing sleeve 958, the fluid passage 962,
and one or more outlet jets 964. During operation of the apparatus 900, the extension tube
5 960 preferably is adapted to convey a hardenable fluidic material from the fluid passage
952 into the fluid passage 962 and then into the outlet jets 964 in order to inject the
hardenable fluidic material into an annular region external to the tubular member 902. In
a preferred embodiment, during operation of the apparatus 900, the sealing sleeve 960
further includes an inlet geometry that permits a conventional plug or dart 974 to become
10 lodged in the inlet of the sealing sleeve 958. In this manner, the fluid passage 962 is
blocked thereby fluidicly isolating the interior region 966 of the tubular member 902. In
a preferred embodiment, one end of the extension tube 960 mates with one end of the
spacer 938 in order to optimally faciliate the transfer of material between the two.
In a preferred embodiment, the extension tube 960 has a substantially annular
15 cross-section. Theextensiontube960maybefabricatedfromanynumberofconventional
commercially available materials such as, for example, steel, aluminum or cast iron. In
a preferred embodiment, the extension tube 960 is fabricated from aluminum in order to
optimally provide drillability of the extension tube 960.
The fluid passage 962 is coupled to the sealing sleeve 958, the extension tube 960,
20 and one or more outlet jets 964. During operation of the apparatus 900, the fluid passage
962 is preferably conveys hardenable fluidic materials. In a preferred embodiment, the
fluid passage 962 is positioned about the centerline of the apparatus 900. In a particularly
preferred embodiment, the fluid passage 962 is adapted to convey hardenable fluidic
materials at pressures and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000
25 gallons/min (0 to 620.528 bar and 0 to 11356.24 litres/minute) in order to optimally
provide fluids at operationally efficient rates.
The outlet jets 964 are coupled to the sealing sleeve 958, the extension tube 960,
and the fluid passage 962. During operation of the apparatus 900, the outlet jets 964
preferably convey hardenable fluidic material from the fluid passage 962 to the region
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exterior of the apparatus 900. In a preferred embodiment, the shoe 908 includes a plurality
of outlet jets 964.
In a preferred embodiment, the outlet jets 964 comprise passages drilled in the
housing 954 and the body of cement 956 in order to simplify the construction of the
5 apparatus 900.
The various elements of the shoe 908 may be coupled using any number of
conventional process such as, for example, threaded connections, cement or machined
from one piece of material. In a preferred embodiment, the various elements of the shoe
908 are coupled using cement.
10 In a preferred embodiment, the assembly 900 is operated substantially as described
above with reference to Figs. 1-8 to create a new section of casing in a wellbore or to
repair a wellbore casing or pipeline.
In particular, in order to extend a wellbore into a subterranean formation, a drill
string is used in a well known manner to drill out material from the subterranean formation
15 to form a new section.
The apparatus 900 for forming a wellbore casing in a subterranean formation is
then positioned in the new section of the wellbore. In a particularly preferred
embodiment, the apparatus 900 includes the tubular member 915. In a preferred
embodiment, a hardenable fluidic sealing hardenable fluidic sealing material is then
20 pumped from a surface location into the fluid passage 91 8. The hardenable fluidic sealing
material then passes from the fluid passage 918 into the interior region 966 of the tubular
member 902 below the mandrel 906. The hardenable fluidic sealing material then passes
from the interior region 966 into the fluid passage 962. The hardenable fluidic sealing
material then exits the apparatus 900 via the outlet jets 964 and fills an annular region
25 between the exterior of the tubular member 902 and the interior wall of the new section
of the wellbore. Continued pumping of the hardenable fluidic sealing material causes the
material to fill up at least a portion of the annular region.
The hardenable fluidic sealing material is preferably pumped into the annular
region at pressures and flow rates ranging, for example, from about 0 to 5,000 psi and 0
30 to 1,500 gallons/min (0 to 344.738 bar and 0 to 5618.12 litres/minute), respectively. In
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a preferred embodiment, the hardenable fluidic sealing material is pumped into the annular
region at pressures and flow rates that are designed for the specific wellbore section in
order to optimize the displacement of the hardenable fluidic sealing material while not
creating high enough circulating pressures such that circulation might be lost and that
5 could cause the wellbore to collapse. The optimum pressures and flow rates are preferably
determined using conventional empirical methods.
The hardenable fluidic sealing material may comprise any number of conventional
commercially available hardenable fluidic sealing materials such as, for example, slag
mix, cement or epoxy. In a preferred embodiment, the hardenable fluidic sealing material
10 comprises blended cements designed specifically for the well section being lined available
from Halliburton Energy Services in Dallas, TX in order to optimally provide support for
the new tubular member while also maintaining optimal flow characteristics so as to
minimize operational difficulties during the displacement of the cement in the annular
region. The optimum composition of the blended cements is preferably determined using
15 conventional empirical methods.
The annular region preferably is filled with the hardenable fluidic sealing material
in sufficient quantities to ensure that, upon radial expansion of the tubular member 902,
the annular region of the new section of the wellbore will be filled with hardenable
material.
20 Once the annular region has been adequately filled with hardenable fluidic sealing
material, a plug or dart 974, or other similar device, preferably is introduced into the fluid
passage 962 thereby fluidicly isolating the interior region 966 of the tubular member 902
from the external annular region. In a preferred embodiment, a non hardenable fluidic
material is then pumped into the interior region 966 causing the interior region 966 to
25 pressurize. In a particularly preferred embodiment, the plug or dart 974, or other similar
device, preferably is introduced into the fluid passage 962 by introducing the plug or dart
974, or other similar device into the non hardenable fluidic material. In this manner, the
amount of cured material within the interior of the tubular members 902 and 915 is
minimized.
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Once the interior region 966 becomes sufficiently pressurized, the tubular members
902and915 are extruded offofthe mandrel 906. The mandrel 906 may be fixed or it may
be expandible. During the extrusion process, the mandrel 906 is raised out of the
expanded portions of the tubular members 902 and 915 using the support member 904.
5 During this extrusion process, the shoe 908 is preferably substantially stationary.
The plug or dart 974 is preferably placed into the fluid passage 962 by introducing
the plug or dart 974 into the fluid passage 918 at a surface location in a conventional
manner. The plug or dart 974 may comprise any number of conventional commercially
available devices for plugging a fluid passage such as, for example, Multiple Stage
10 Cementer (MSC) latch-down plug, Omega latch-down plug or three-wiper latch down
plug modified in accordance with the teachings of the present disclosure. In a preferred
embodiment, the plug or dart 974 comprises a MSC latch-down plug available from
Halliburton Energy Services in Dallas, TX.
After placement of the plug or dart 974 in the fluid passage 962, the non
1 5 hardenable fluidic material is preferably pumped into the interior region 966 at pressures
and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min
(34.47 to 620.53 bar and 151 .42 to 1 1356.24 litres/minute) in order to optimally extrude
the tubular members 902 and 915 offofthe mandrel 906.
For typical tubular members 902 and 915, the extrusion of the tubular members
20 902 and 915 off of the expandable mandrel will begin when the pressure of the interior
region 966 reaches approximately (34,47 to 620.53 bar). In a preferred embodiment, the
extrusion of the tubular members 902 and 915 offofthe mandrel 906 begins when the
pressure of the interior region 966 reaches approximately 1,200 to 8,500 psi (82.737 to
586.054 bar) with a flow rate of about 40 to 1 250 gallons/minute ( 1 5 1 .4 1 6 to 4,73 1 .765
25 litres/minute).
During the extrusion process, the mandrel 906 may be raised out of the expanded
portions of the tubular members 902 and 915 at rates ranging, for example, from about 0
to 5 ft/sec (0 to 1 .524 metres). In a preferred embodiment, during the extrusion process,
the mandrel 906 is raised out of the expanded portions of the tubular members 902 and
30 915 at rates ranging from about 0 to 2 ft/sec (0 to 0.6096 metres) in order to optimally
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provide pulling speed fast enough to permit efficient operation and permit full expansion
of the tubular members 902 and 915 prior to curing of the hardenable fluidic sealing
material; but not so fast that timely adjustment of operating parameters during operation
is prevented.
5 When the upper end portion of the tubular member 915 is extruded off of the
mandrel 906, the outer surface of the upper end portion of the tubular member 915 will
preferably contact the interior surface of the lower end portion of the existing casing to
form an fluid tight overlapping joint. The contact pressure of the overlapping joint may
range, for example, from approximately 50 to 20,000 psi (3.447 to 137.95 bar). In a
10 preferred embodiment, the contact pressure of the overlappingjoint between the upper end
of the tubular member 915 and the existing section of wellbore casing ranges from
approximately 400 to 10,000 psi (27.58 to 689.476 bar) in order to optimally provide
contact pressure to activate the sealing members and provide optimal resistance such that
the tubular member 915 and existing wellbore casing will cany typical tensile and
15 compressive loads.
In a preferred embodiment, the operating pressure and flow rate of the non
hardenable fluidic material will be controllably ramped down when the mandrel 906
reaches the upper end portion of the tubular member 915. In this manner, the sudden
release of pressure caused by the complete extrusion of the tubular member 915 off of the
20 expandable mandrel 906 can be minimized. In a preferred embodiment, the operating
pressure is reduced in a substantially linear fashion from 100% to about 10% during the
end of the extrusion process beginning when the mandrel 906 has completed
approximately all but about the last 5 feet (1.524 metres) of the extrusion process.
In an alternative preferred embodiment, the operating pressure and/or flow rate of
25 the hardenable fluidic sealing material and/or the non hardenable fluidic material are
controlled during all phases of the operation of the apparatus 900 to minimize shock.
Alternatively, or in combination, a shock absorber is provided in the support
member 904 in order to absorb the shock caused by the sudden release of pressure.
Alternatively, or in combination, a mandrel catching structure is provided above
30 the support member 904 in order to catch or at least decelerate the mandrel 906.
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Once the extrusion process is completed, the mandrel 906 is removed from the
wellbore. In a preferred embodiment, either before or after the removal of the mandrel
906, the integrity of the fluidic seal of the overlapping joint between the upper portion of
the tubular member 915 and the lower portion of the existing casing is tested using
5 conventional methods. If the fluidic seal of the overlapping joint between the upper
portion of the tubular member 915 and the lower portion of the existing casing is
satisfactory, then the uncured portion of any of the hardenable fluidic sealing material
within the expanded tubular member 915 is then removed in a conventional manner. The
hardenable fluidic sealing material within the annular region between the expanded
10 tubular member 915 and the existing casing and new section of wellbore is then allowed
to cure.
Preferably any remaining cured hardenable fluidic sealing material within the
interior of the expanded tubular members 902 and 91 5 is then removed in a conventional
manner using a conventional drill string. The resulting new section of casing preferably
1 6 includes the expanded tubular members 902 and 9 1 5 and an outer annular layer of cured
hardenable fluidic sealing material. The bottom portion of the apparatus 900 comprising
the shoe 908 may then be removed by drilling out the shoe 908 using conventional drilling
methods.
In an alternative embodiment, during the extrusion process, it may be necessary to
20 remove the entire apparatus 900 from the interior of the wellbore due to a malfunction.
In this circumstance, a conventional drill string is used to drill out the interior sections of
the apparatus 900 in order to facilitate the removal of the remaining sections. In a
preferred embodiment, the interior elements of the apparatus 900 are fabricated from
materials such as, for example, cement and aluminum, that permit a conventional drill
25 string to be employed to drill out the interior components.
In particular, in a preferred embodiment, the composition of the interior sections
of the mandrel 906 and shoe 908, including one or more of the body of cement 932, the
spacer 938, the sealing sleeve 942, the upper cone retainer 944, the lubricator mandrel
946, the lubricator sleeve 948, the guide 950, the housing 954, the body of cement 956,
30 the sealing sleeve 958, and the extension tube 960, are selected to permit at least some of
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these components to be drilled out using conventional drilling methods and apparatus. In
this manner, in the event of a malfunction downhole, the apparatus 900 may be easily
removed from the wellbore.
Referring now to Figs. 10a, 10b, 10c, lOd, lOe, lOf, and lOg a method and
5 apparatus for creating a tie-back liner in a wellbore will now be described. As illustrated
in Fig. 10a, a wellbore 1000 positioned in a subterranean formation 1002 includes a first
casing 1004 and a second casing 1006.
The first casing 1 004 preferably includes a tubular liner 1 008 and a cement annulus
1010. The second casing 1006 preferably includes a tubular liner 1012 and a cement
10 annulus 1 014. In apreferred embodiment, the second casing 1 006 is formed by expanding
a tubular member substantially as described above with reference to Figs. l-9c or below
with reference to Figs. 1 la- 1 If.
In a particularly preferred embodiment, an upper portion of the tubular liner 1 012
overlaps with a lower portion of the tubular liner 1008. In a particularly preferred
15 embodiment, an outer surface of the upper portion of the tubular liner 1012 includes one
or more sealing members 1016forprovidingafluidicseal between the tubular liners 1008
and 1012.
Referring to Fig. 10b, in order to create a tie-back liner that extends from the
overlap between the first and second casings, 1004 and 1006, an apparatus 1100 is
20 preferably provided that includes an expandable mandrel or pig 1 1 05 , a tubular member
1 1 10, a shoe 1 1 IS, one or more cup seals 1 120, a fluid passage 1 130, a fluid passage 1 135,
one or more fluid passages 1 140, seals 1 145, and a support member 1 150.
The expandable mandrel or pig 1 105 is coupled to and supported by the support
member 1 1 50. The expandable mandrel 1 105 is preferably adapted to controllably expand
25 in a radial direction. The expandable mandrel 1105 may comprise any number of
conventional commercially available expandable mandrels modified in accordance with
the teachings of the present disclosure. In a preferred embodiment, the expandable
mandrel 1 1 05 comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat.
No. 5,348,095, the disclosure of which is incorporated herein by reference, modified in
30 accordance with the teachings of the present disclosure.
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The tubular member 1 1 1 0 is coupled to and supported by the expandable mandrel
1 105. The tubular member 1 105 is expanded in the radial direction and extruded off of
the expandable mandrel 1 105. The tubular member 1110 may be fabricated from any
number of materials such as, for example, Oilfield Country Tubular Goods, 1 3 chromium
5 tubing or plastic piping. In a preferred embodiment, the tubular member 1110 is
fabricated from Oilfield Country Tubular Goods.
The inner and outer diameters of the tubular member 1110 may range, for example,
from approximately,0.75 to 47 inches and 1.05 to 48 inches ( 1 .905 to 199.38 centimetres
and 2.667 to 1 2 1 .92 centimetres), respectively. In a preferred embodiment, the inner and
10 outer diameters of the tubular member 1110 range from about 3 to 15.5 inches and 3.5 to
16 inches (7.62 to 39.37 centimelres and 8.89 to 40.64 centimetres), respectively in order
to optimally provide coverage for typical oilfield casing sizes. The tubular member 1110
preferably comprises a solid member.
In a preferred embodiment, the upper end portion of the tubular member 1 1 10 is
15 slotted, perforated, or otherwise modified to catch or slow down the mandrel 1 1 05 when
it completes the extrusion of tubular member 1 1 10. In a preferred embodiment, the length
of the tubular member 1 1 1 0 is limited to minimize the possibility ofbuckling. For typical
tubular member 1110 materials, the length of the tubular member 1 1 10 is preferably
limited to between about 40 to 20,000 feet (12.192 to 6096.00 metres) in length.
20 The shoe 1 1 1 5 is coupled to the expandable mandrel 1 1 05 and the tubular member
1110. The shoe 11 15 includes the fluid passage 1 135. The shoe 11 15 may comprise any
number of conventional commercially available shoes such as, for example, Super Seal
II float shoe, Super Seal n Down- Jet float shoe or a guide shoe with a sealing sleeve for
a latch down plug modified in accordance with the teachings of the present disclosure. In
25 a preferred embodiment, the shoe 1115 comprises an aluminum down-j et guide shoe with
a sealing sleeve for a latch-down plug with side ports radiating off of the exit flow port
available from Halliburton Energy Services in Dallas, TX, modified in accordance with
the teachings of the present disclosure, in order to optimally guide the tubular member
1 100 to the overlap between the tubular member 1 100 and the casing 1012, optimally
30 fluidicly isolate the interior of the tubular member 1 100 after the latch down plug has
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seated, and optimally permit drilling out of the shoe 1115 after completion of the
expansion and cementing operations.
In a preferred embodiment, the shoe 1115 includes one or more side outlet ports
1 1 40 in fluidic communication with the fluid passage 1 1 35. In this manner, the shoe 1115
5 injects hardenable fluidic sealing material into the region outside the shoe 1115 and
tubular member 1110. In a preferred embodiment, the shoe 1115 includes one or more of
the fluid passages 1 140 each having an inlet geometry that can receive a dart and/or a ball
sealing member. In this manner, the fluid passages 11 40 can be sealed off by introducing
a plug, dart and/or ball sealing elements into the fluid passage 1 130.
10 The cup seal 1 120 is coupled to and supported by the support member 1 1 50. The
cup seal 1 120 prevents foreign materials from entering the interior region of the tubular
member 1110 adjacent to the expandable mandrel 1 1 05. The cup seal 1 1 20 may comprise
any number of conventional commercially available cup seals such as, for example, TP
cups or Selective Injection Packer (SIP) cups modified in accordance with the teachings
15 of the present disclosure. In a preferred embodiment, the cup seal 1 120 comprises a SIP
cup, available from Halliburton Energy Services in Dallas, TX in order to optimally
provide a barrier to debris and contain a body of lubricant.
The fluid passage 1 130 permits fluidic materials to be transported to and from the
interiorregionofthetubularmemberlllObelowtheexpandablemandrel 1105. The fluid
20 passage 1130 is coupled to and positioned within the support member 1150 and the
expandable mandrel 1105. The fluid passage 1 130 preferably extends from a position
adjacent to the surface to the bottom of the expandable mandrel 1 105. The fluid passage
1130ispreferablypositionedalongacenterlineoftheapparatus 1100. The fluid passage
1 1 30 is preferably selected to transport materials such as cement, drilling mud or epoxies
25 at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000
psi (0 to 11356.24 litres/minute and 0 to 620.528 bar) in order to optimally provide
sufficient operating pressures to circulate fluids at operationally efficient rates.
The fluid passage 1135 permits fluidic materials to be transmitted from fluid
passage 1 130 to the interior of the tubular member 1110 below the mandrel 1 105.
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The fluid passages 1 140 permits fluidic materials to be transported to and from the
region exterior to the tubular member 1 1 10 and shoe 1115. The fluid passages 1 140 are
coupled to and positioned within the shoe 1 1 1 5 in fluidic communication with the interior
region of the tubular member 1110 below the expandable mandrel 1105. The fluid
5 passages 1 1 40 preferably have a cross-sectional shape that permits a plug, or other similar
device, to be placed in the fluid passages 1 140 to thereby block further passage of fluidic
materials. In this manner, the interior region of the tubular member 1110 below the
expandable mandrel 1 105 can be fluidiciy isolated from the region exterior to the tubular
member 1 105. This permits the interior region of the tubular member 1110 below the
10 expandable mandrel 1 105 to be pressurized.
The fluid passages 1 140 are preferably positioned along the periphery of the shoe
1115. The fluid passages 1 1 40 are preferably selected to convey materials such as cement,
drilling mud or epoxies at flow rates and pressures ranging from about 0 to 3,000
gallons/minute and 0 to 9,000 psi (0 to 1 1356.24 litres/minute and 0 to 620.528 bar) in
15 order to optimally fill the annular region between the tubular member 1 1 10 and the tubular
liner 1008 with fluidic materials. In a preferred embodiment, the fluid passages 1 140
include an inlet geometry that can receive a dart and/or a ball sealing member. In this
manner, the fluid passages 1 140 can be sealed off by introducing a plug, dart and/or ball
sealing elements into the fluid passage 1 130. In a preferred embodiment, the apparatus
20 1 1 00 includes a plurality of fluid passage 1 140.
In an alternative embodiment, the base of the shoe 1115 includes a single inlet
passage coupled to the fluid passages 1 140 that is adapted to receive a plug, or other
similar device, to permit the interior region of the tubular member 1 1 10 to be fluidiciy
isolated from the exterior of the tubular member 1110.
25 The seals 1 145 are coupled to and supported by a lower end portion of the tubular
member 1110. The seals 1 145 are further positioned on an outer surface of the lower end
portion of the tubular member 1110. The seals 1 145 permit the overlapping joint between
the upper end portion of the casing 1012 and the lower end portion of the tubular member
1 1 10 to be fluidiciy sealed.
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The seals 1 145 may comprise any number of conventional commercially available
seals such as, for example, lead, rubber, Teflon (RTM) or epoxy seals modified in
accordance with the teachings of the present disclosure. In a preferred embodiment, the
seals 1 145 comprise seals molded from Stratalock epoxy available from Halliburton
5 Energy Services in Dallas, TX in order to optimally provide a hydraulic seal in the
overlapping joint and optimally provide load carrying capacity to withstand the range of
typical tensile and compressive loads.
In a preferred embodiment, the seals 1145 are selected to optimally provide a
sufficient frictional force to support the expanded tubular member 1110 from the tubular
10 liner 1008. In a preferred embodiment, the frictional force provided by the seals 1 145
ranges from about 1,000 to 1,000,000 lbf (0.478803 to 478.803 bar) in tension and
compression in order to optimally support the expanded tubular member 1110.
The support member 1150 is coupled to the expandable mandrel 1 105, tubular
member 1110, shoe 1 1 1 5, and seal 1 1 20. The support member 1 1 50 preferably comprises
15 an annular member having sufficient strength to carry the apparatus 1 1 00 into the wellbore
1000. In a preferred embodiment, the support member 1 1 50 further includes one or more
conventional centralizers (not illustrated) to help stabilize the tubular member 1110.
In a preferred embodiment, a quantity of lubricant 1 1 50 is provided in the annular
region above the expandable mandrel 1 1 05 within the interior of the tubul ar member 1110.
20 In this manner, the extrusion of the tubular member 1 1 1 0 off of the expandable mandrel
1105 is facilitated. The lubricant 1150 may comprise any number of conventional
commercially available lubricants such as, for example, Lubriplate (RTM), chlorine based
lubricants or Climax 1500 Antiseize (3100). In a preferred embodiment, the lubricant
1150 comprises Climax 1500 Antiseize (3100) available from Climax Lubricants and
25 Equipment Co. in Houston, TX in order to optimally provide lubrication for the extrusion
process.
In a preferred embodiment, the support member 1 150 is thoroughly cleaned prior
to assembly to the remaining portions of the apparatus 1100. In this manner, the
introduction of foreign material into the apparatus 1 1 00 is minimized. This minimizes the
30 possibility of foreign material clogging the various flow passages and valves of the
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apparatus 1100 and to ensure that no foreign material interferes with the expansion
mandrel 1 105 during the extrusion process.
In a particularly preferred embodiment, the apparatus 1 1 00 includes a packer 1 1 55
coupled to the bottom section of the shoe 1 1 15 for fluidicly isolating the region of the
5 wellbore 1000 below the apparatus 1 100. In this manner, fluidic materials are prevented
from entering the region of the wellbore 1 000 below the apparatus 1 1 00. The packer 1 1 55
may comprise any number of conventional commercially available packers such as, for
example, EZ Drill Packer, EZ SV Packer or a drillable cement retainer. In a preferred
embodiment, the packer 1155 comprises an EZ Drill Packer available from Halliburton
10 Energy Services in Dallas, TX. In an alternative embodiment, a high gel strength pill may
be set below the tie-back in place of the packer 1155. In another alternative embodiment,
the packer 1155 may be omitted.
In a preferred embodiment, before or after positioning the apparatus 1 100 within
the wellbore 1 100, a couple of wellbore volumes are circulated in order to ensure that no
1 5 foreign materials are located within the wellbore 1 000 that might clog up the various flow
passages and valves of the apparatus 1 1 00 and to ensure that no foreign material interferes
with the operation of the expansion mandrel 1 105.
As illustrated in Fig. 10c, a hardenable fluidic sealing material 1160 is then
pumped from a surface location into the fluid passage 1130. The material 1160 then
20 passes from the fluid passage 1 130 into the interior region of the tubular member 1110
below the expandable mandrel 1 105, The material 1 160 then passes from the interior
region of the tubular member 1110 into the fluid passages 1 140. The material 1 160 then
exits the apparatus 1 100 and fills the annular region between the exterior of the tubular
member 1110 and the interior wall of the tubular liner 1008. Continued pumping of the
25 material 1 160 causes the material 1 160 to fill up at least a portion of the annular region.
The material 1 160 may be pumped into the annular region at pressures and flow
rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500 gallons/min (0 to
344.738 bar and 0 to 561 8. 1 2 litres/minute), respectively. In a preferred embodiment, the
material 1 160 is pumped into the annular region at pressures and flow rates specifically
30 designed for the casing sizes being run, the annular spaces being filled, the pumping
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equipment available, and the properties of the fluid being pumped. The optimum flow
rates and pressures are preferably calculated using conventional empirical methods.
The hardenable fluidic sealing material 1160 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such as, for
5 example, slag mix, cement or epoxy. In a preferred embodiment, the hardenable fluidic
sealing material 1 160 comprises blended cements specifically designed for well section
being tied-back, available from Halliburton Energy Services in Dallas, TX in order to
optimally provide proper support for the tubular member 1110 while maintaining optimum
flow characteristics so as to minimize operational difficulties during the displacement of
10 cement in the annular region. The optimum blend of the blended cements are preferably
determined using conventional empirical methods.
The annular region may be filled with the material 1 1 60 in sufficient quantities to
ensure that, upon radial expansion of the tubular member 1110, the annular region will be
filled with material 1 160.
15 As illustrated in Fig. 1 Od, once the annular region has been adequately filled with
material 1 1 60, one or more plugs 1 1 65 , or other similar devices, preferably are introduced
into the fluid passages 1 140 thereby fluidicly isolating the interior region of the tubular
member 1110 from the annular region external to the tubular member 1 1 1 0 . In a preferred
embodiment, a non hardenable fluidic material 1161 is then pumped into the interior
20 region of the tubular member 1110 below the mandrel 1 105 causing the interior region to
pressurize. In a particularly preferred embodiment, the one or more plugs 1 1 65, or other
similar devices, are introduced into the fluid passage 1 140 with the introduction of the non
hardenable fluidic material. In this manner, the amount of hardenable fluidic material
within the interior of the tubular member 1 1 10 is minimized.
25 As illustrated in Fig. 1 Oe, once the interior region becomes sufficiently pressurized,
the tubular member 1 1 10 is extruded off of the expandable mandrel 1 105. During the
extrusion process, the expandable mandrel 1 105 is raised out of the expanded portion of
the tubular member 1110.
The plugs 1 165 are preferably placed into the fluid passages 1 140 by introducing
30 the plugs 1 165 into the fluid passage 1 1 30 at a surface location in a conventional manner.
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The plugs 1 1 65 may comprise any number of conventional commercially available devices
from plugging a fluid passage such as, for example, brass balls, plugs, rubber balls, or
darts modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the plugs 1 165 comprise low density rubber balls. In
5 an alternative embodiment, for a shoe 1 105 having a common central inlet passage, the
plugs 1 165 comprise a single latch down dart.
After placement of the plugs 1 165 in the fluid passages 1 140, the non hardenable
fluidic material 1 161 is preferably pumped into the interior region of the tubular member
1110 below the mandrel 1 1 05 at pressures and flow rates ranging from approximately 500
10 to 9,000 psi and 40 to 3,000 gallons/min (34.47 to 620.53 bar and 151.42 to 1 1356.24
litres/minute).
In a preferred embodiment, after placement of the plugs 1 165 in the fluid passages 1 140,
the non hardenable fluidic material 1 161 is preferably pumped into the interior region of
the tubular member 1110 below the mandrel 1 1 05 at pressures and flow rates ranging from
15 approximately 1200 to 8500 psi and 40 to 1250 gallons/min (82.737 to 586.054 bar to
151.42 to 4731.76 litres/minute) in order to optimally provide extrusion of typical
tubulars.
For typical tubular members 1 1 10, the extrusion of the tubular member 1 1 10 off
of the expandable mandrel 1 105 will begin when the pressure of the interior region of the
20 tubular member 1 110 below the mandrel 1105 reaches, for example, approximately 1200
to 8500 psi (82.737 to 586.054 bar). In a preferred embodiment, the extrusion of the
tubular member 1 1 1 0 off of the expandable mandrel 1 1 05 begins when the pressure of the
interiorregionofthetubularmember 11 10 below the mandrel 1 105 reaches approximately
1200 to 8500 psi (82.737 to 586.054 bar).
25 During the extrusion process, the expandable mandrel 1 1 05 may be raised out of
the expanded portion of the tubular member 1 1 10 at rates ranging, for example, from
about 0 to 5 ft/sec (0 to 1 .524 metres). In a preferred embodiment, during the extrusion
process, the expandable mandrel 1 105 is raised out of the expanded portion of the tubular
member 1 1 10 at rates ranging from about 0 to 2 ft/sec (0 to 0.6096 metres) in order to
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optimally provide permit adjustment of operational parameters, and optimally ensure that
the extrusion process will be completed before the material 1 160 cures.
In a preferred embodiment, at least a portion 1 1 80 of the tubular member 11 1 0 has
an internal diameter less than the outside diameter of the mandrel 1 105. In this manner,
5 when the mandrel 1 1 05 expands the section 1 1 80 of the tubular member 1 1 10, at least a
portion of the expanded section 1 1 80 effects a seal with at least the wellbore casing 1012.
In a particularly preferred embodiment, the seal is effected by compressing the seals 1016
between the expanded section 1180 and the wellbore casing 1012. In a preferred
embodiment, the contact pressure of the joint between the expanded section 1 1 80 of the
10 tubular member 1 1 1 0 and the casing 1012 ranges from about 500 to 1 0,000 psi (34.47 to
689.48 bar) in order to optimally provide pressure to activate the sealing members 1 145
and provide optimal resistance to ensure that the joint will withstand typical extremes of
tensile and compressive loads.
In an alternative preferred embodiment, substantially all of the entire length of the
15 tubular member 1110 has an internal diameter less than the outside diameter of the
mandrel 1105. In this manner, extrusion ofthe tubular member 11 10 by the mandrel 1105
results in contact between substantially all of the expanded tubular member 1110 and die
existing casing 1 008 . In a preferred embodiment, the contact pressure of the joint between
the expanded tubular member 11 10 and the casings 1008 and 1012ranges from about 500
20 to 10,000 psi (34.47 to 689.48 bar) in order to optimally provide pressure to activate the
sealing members 1145 and provide optimal resistance to ensure that the joint will
withstand typical extremes of tensile and compressive loads.
In a preferred embodiment, the operating pressure and flow rate ofthe material
1 161 is controllably ramped down when the expandable mandrel 1 105 reaches the upper
25 end portion ofthe tubular member 1110. In this manner, the sudden release of pressure
caused by the complete extrusion of the tubular member 1110 off of the expandable
mandrel 1 1 05 can be minimized. In a preferred embodiment, the operating pressure ofthe
fluidic material 1 1 61 is reduced in a substantially linear fashion from 1 00% to about 1 0%
during the end ofthe extrusion process beginning when the mandrel 1 105 has completed
30 approximately all but about 5 feet (1.524 metres) of the extrusion process.
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Alternatively, or in combination, a shock absorber is provided in the support
member 1 150 in order to absorb the shock caused by the sudden release of pressure.
Alternatively, or in combination, a mandrel catching structure is provided in the
upper end portion of the tubular member 1 1 10 in order to catch or at least decelerate the
5 mandrel 1105.
Referring to Fig. lOf, once the extrusion process is completed, the expandable
mandrel 1 105 is removed from the wellbore 1000. In a preferred embodiment, either
before or after the removal of the expandable mandrel 1 105, the integrity of the fluidic
seal of the joint between the upper portion of the tubular member 1110 and the upper
10 portion of the tubular liner 1 108 is tested using conventional methods. If the fluidic seal
of the joint between the upper portion of the tubular member 1110 and the upper portion
of the tubular liner 1008 is satisfactory, then the uncured portion of the material 1 160
within the expanded tubular member 1 1 1 0 is then removed in a conventional manner. The
material 1 1 60 within the annular region between the tubular member 1110 and the tubular
15 liner 1008 is then allowed to cure.
As illustrated in Fig. I Of, preferably any remaining cured material 1 1 60 within the
interior of the expanded tubular member 1 1 10 is then removed in a conventional manner
using a conventional drill string. The resulting tie-back liner of casing 1 170 includes the
expanded tubular member 1110 and an outer annular layer 1 1 75 of cured material 1 160.
20 As illustrated in Fig. lOg, the remaining bottom portion of the apparatus 1 100
comprising the shoe 1115 and packer 1 155 is then preferably removed by drilling out the
shoe 1115 and packer 1 155 using conventional drilling methods.
In a particularly preferred embodiment, the apparatus 1100 incorporates the
apparatus 900.
25 Referring now to Figs. 1 1 a- 1 1 f, an embodiment of an apparatus and method for
hanging a tubular liner off of an existing wellbore casing will now be described. As
illustrated in Fig. 1 la, a wellbore 1200 is positioned in a subterranean formation 1205.
The wellbore 1200 includes an existing cased section 1210 having a tubular casing 1215
and an annular outer layer of cement 1220.
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In order to extend the wellbore 1200 into the subterranean formation 1205, a drill
string 1225 is used in a well known manner to drill out material from the subterranean
formation 1205 to form a new section 1230.
As illustrated in Fig. 1 lb, an apparatus 1300 for forming a wellbore casing in a
5 subterranean formation is then positioned in the new section 1230 of the wellbore 100.
The apparatus 1300 preferably includes an expandable mandrel or pig 1305, a tubular
member 13 10, a shoe 1315, a fluid passage 1320, a fluid passage 1330, a fluid passage
1335, seals 1340, a support member 1345, and a wiper plug 1350.
The expandable mandrel 1 305 is coupled to and supported by the support member
10 1345. The expandable mandrel 1305 is preferably adapted to controllably expand in a
radial direction. The expandable mandrel 1 305 may comprise any number of conventional
commercially available expandable mandrels modified in accordance with the teachings
of the present disclosure. In a preferred embodiment, the expandable mandrel 1305
comprises a hydraulic expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095,
15 the disclosure of which is incorporated herein by reference, modified in accordance with
the teachings of the present disclosure.
The tubular member 1 3 1 0 is coupled to and supported by the expandable mandrel
1305. The tubular member 1310 is preferably expanded in the radial direction and
extruded off of the expandable mandrel 1305. The tubular member 1310 may be
20 fabricated from any number of materials such as, for example, Oilfield Country Tubular
Goods (OCTG), 13 chromium steel tubing/casing or plastic casing. In a preferred
embodiment, the tubular member 13 10 is fabricated from OCTG. The inner and outer
diameters of the tubular member 1310 may range, for example, from approximately 0.75
to 47 inches and 1.05 to 48 inches (1.905 to 119.38 and 2.667 to 121.92 centimetres),
25 respectively. In a preferred embodiment, the inner and outer diameters of the tubular
member 1310 range from about 3 to 15.5 inches and 3.5 to 16 inches (7.62 to 39.37
centimetres and 8.89 to 40.64 centimetres), respectively in order to optimally provide
minimal telescoping effect in the most commonly encountered wellbore sizes.
In a preferred embodiment, the tubular member 1310 includes an upper portion
30 1355, an intermediate portion 1360, and a lower portion 1365 . In apreferred embodiment,
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the wall thickness and outer diameter of the upper portion 1355 of the tubular member
1310 range from about 3/8 to 1 Vi inches and 3 Vi to 16 inches (0.9525 to 3.81 and 8.89
to 40.64 centimetres), respectively. In a preferred embodiment, the wall thickness and
outer diameter of the intermediate portion 1360 of the tubular member 1310 range from
5 about 0.625 to 0.75 inches and 3 to 19 inches (1.5875 to 1.905 and 7.62 to 48.26
centimetres), respectively. In a preferred embodiment, the wall thickness and outer
diameter of the lower portion 1365 of the tubular member 1310 range from about 3/8 to
1.5 inches and 3.5 to 16 inches (0.9525 to 3.81 and 8.89 to 40.64 centimetres)
respectively.
10 In a particularly preferred embodiment, the outer diameter of the lower portion
1 365 of the tubular member 1 3 1 0 is significantly less than the outer diameters of the upper
and intermediate portions, 1355 and 1360, of the tubular member 1310 in order to
optimize the formation of a concentric and overlapping arrangement of wellbore casings.
In this manner, as will be described below with reference to Figs. 12 and 13, a wellhead
15 system is optimally provided. In a preferred embodiment, the formation of a wellhead
system does not include the use of a hardenable fluidic material.
In a particularly preferred embodiment, the wall thickness of the intermediate
section 1360 of the tubular member 1310 is less than or equal to the wall thickness of the
upper and lower sections, 1355 and 1365, of the tubular member 1310 in order to
20 optimally faciliate the initiation of the extrusion process and optimally permit the
placement of the apparatus in areas of the wellbore having tight clearances.
The tubular member 1310 preferably comprises a solid member. In a preferred
embodiment, the upper end portion 1355 of the tubular member 1310 is slotted,
perforated, or otherwise modified to catch or slow down the mandrel 1305 when it
25 completes the extrusion of tubular member 1310. In a preferred embodiment, the length
of the tubular member 1 3 1 0 is limited to minimize the possibility of buckling. For typical
tubular member 1310 materials, the length of the tubular member 1310 is preferably
limited to between about 40 to 20,000 feet (12.192 to 6096.00 metres) in length.
The shoe 1 3 1 5 is coupled to the tubular member 1 3 1 0. The shoe 1315 preferably
30 includes fluid passages 1330 and 1335. The shoe 1315 may comprise any number of
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conventional commercially available shoes such as, for example, Super Seal II float shoe,
Super Seal II Down- Jet float shoe or guide shoe with a sealing sleeve for a latch-down
plug modified in accordance with the teachings of the present disclosure. In a preferred
embodiment, the shoe 1315 comprises an aluminum down-jet guide shoe with a sealing
5 sleeve for a latch-down plug available from Halliburton Energy Services in Dallas, TX,
modified in accordance with the teachings of the present disclosure, in order to optimally
guide the tubular member 1310 into the wellbore 1200, optimally fluidicly isolate the
interior of the tubular member 1310, and optimally permit the complete drill out of the
shoe 1315 upon the completion of the extrusion and cementing operations.
10 In a preferred embodiment, the shoe 1315 further includes one or more side outlet
ports in fluidic communication with the fluid passage 1330. In this manner, the shoe 1315
preferably injects hardenable fluidic sealing material into the region outside the shoe 1315
and tubular member 1310. In a preferred embodiment, the shoe 1315 includes the fluid
passage 1330 having an inlet geometry that can receive a fluidic sealing member. In this
15 manner, the fluid passage 1330 can be sealed off by introducing a plug, dart and/or ball
sealing elements into the fluid passage 1330.
The fluid passage 1320 permits fluidic materials to be transported to and from the
interiorregion of the tubular member 1310 below the expandable mandrel 1305. The fluid
passage 1320 is coupled to and positioned within the support member 1345 and the
20 expandable mandrel 1305. The fluid passage 1320 preferably extends from a position
adjacent to the surface to the bottom of the expandable mandrel 1 305. The fluid passage
1 320 is preferably positioned along a centerline of the apparatus 1 300. The fluid passage
1 320 is preferably selected to transport materials such as cement, drilling mud, or epoxies
at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000
25 psi (0 to 11356.24 litres/minute and 0 to 620.528 bar) in order to optimally provide
sufficient operating pressures to circulate fluids at operationally efficient rates.
The fluid passage 1330 permits fluidic materials to be transported to and from the
region exterior to the tubular member 1310 and shoe 1315. The fluid passage 1330 is
coupled to and positioned within the shoe 1 3 1 5 in fluidic communication with the interior
30 region 1370 of the tubular member 1310 below the expandable mandrel 1305. The fluid
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passage 1330 preferably has a cross-sectional shape that permits a plug, or other similar
device, to be placed in fluid passage 1330 to thereby block further passage of fluidic
materials. In this manner, the interior region 1 370 of the tubular member 1310 below the
expandable mandrel 1305 can be fluidicly isolated from the region exterior to the tubular
5 member 1310. This permits the interior region 1370 of the tubular member 1310 below
the expandable mandrel 1305 to be pressurized. The fluid passage 1330 is preferably
positioned substantially along the centerline of the apparatus 1300.
The fluid passage 1330 is preferably selected to convey materials such as cement,
drilling mud or epoxies at flow rates and pressures ranging from about iO to 3,000
10 gallons/minute and 0 to 9,000 psi (0 to 1 1356.24 litres/minute and 0 to 620.528 bar) in
order to optimally fill the annular region between the tubular member 1 3 1 0 and the new
section 1 230 of the wellbore 1 200 with fluidic materials. In a preferred embodiment, the
fluid passage 1 330 includes an inlet geometry that can receive a dart and/or a ball sealing
member. In this manner, the fluid passage 1330 can be sealed off by introducing a plug,
15 dart and/or ball sealing elements into the fluid passage 1320.
The fluid passage 1 335 permits fluidic materials to be transported to and from the
region exterior to the tubular member 1310 and shoe 1315. The fluid passage 1335 is
coupled to and positioned within the shoe 1315 in fluidic communication with the fluid
passage 1330. The fluid passage 1335 is preferably positioned substantially along the
20 centerline of the apparatus 1300. The fluid passage 1 335 is preferably selected to convey
materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from
about 0 to 3,000 gallons/minute and 0 to 9,000 psi (0 to 1 1356.24 litres/minute and 0 to
620.528 bar) in order to optimally fill the annular region between the tubular member
1310 and the new section 1230 of the wellbore 1200 with fluidic materials.
25 The seals 1 340 are coupled to and supported by the upper end portion 1 355 of the
tubular member 1310. The seals 1340 are further positioned on an outer surface of the
upper end portion 1355 of the tubular member 1310. The seals 1340 permit the
overlapping j oint between the lower end portion of the casing 1215 and the upper portion
1355 of the tubular member 1310 to be fluidicly sealed. The seals 1340 may comprise
30 any number of conventional commercially available seals such as, for example, lead,
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rubber, Teflon (RTM), or epoxy seals modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the seals 1 340 comprise seals molded from
Stratalock epoxy available from Halliburton Energy Services in Dallas, TX in order to
optimally provide a hydraulic seal in the annulus of the overlapping joint while also
5 creating optimal load bearing capability to withstand typical tensile and compressive
loads.
In a preferred embodiment, the seals 1340 are selected to optimally provide a
sufficient frictional force to support the expanded tubular member 1310 from the existing
casing 1215. In a preferred embodiment, the frictional force provided by the seals 1340
10 ranges from about 1,000 to 1,000,000 lbf (0.478803 to 478.803 bar) in order to optimally
support the expanded tubular member 1310.
The support member 1345 is coupled to the expandable mandrel 1305, tubular
member 1310, shoe 1315, and seals 1340. The support member 1345 preferably
comprises an annular member having sufficient strength to carry the apparatus 1300 into
15 the new section 1230 of the wellbore 1200. In a preferred embodiment, the support
member 1345 further includes one or more conventional centralizers (not illustrated) to
help stabilize the tubular member 1310.
In a preferred embodiment, the support member 1 345 is thoroughly cleaned prior
to assembly to the remaining portions of the apparatus 1300. In this manner, the
20 introduction of foreign material into the apparatus 1 300 is minimized. This minimizes the
possibility of foreign material clogging the various flow passages and valves of the
apparatus 1300 and to ensure that no foreign material interferes with the expansion
process.
The wiper plug 1350 is coupled to the mandrel 1305 within the interior region
25 1370ofthetubularmember 1310. Thewiperplug 13 50 includes a fluid passage 1375that
is coupled to the fluid passage 1320. The wiper plug 1350 may comprise one or more
conventional commercially available wiper plugs such as, for example, Multiple Stage
Cementer latch-down plugs, Omega latch-down plugs or three-wiper latch-down plug
modified in accordance with the teachings of the present disclosure. In a preferred
30 embodiment, the wiper plug 1350 comprises a Multiple Stage Cementer latch-down plug
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available from Halliburton Energy Services in Dallas, TX modified in a conventional
manner for releasable attachment to the expansion mandrel 1305.
In a preferred embodiment, before or after positioning the apparatus 1 300 within
the new section 1230 of the wellbore 1200, a couple of wellbore volumes are circulated
5 in order to ensure that no foreign materials are located within the wellbore 1 200 that might
clog up the various flow passages and valves of the apparatus 1300 and to ensure that no
foreign material interferes with the extrusion process.
As illustrated in Fig. 11c, a hardenable fluidic sealing material 1380 is then
pumped from a surface location into the fluid passage 1320. The material 1380 then
10 passes from the fluid passage 1320, through the fluid passage 1375, and into the interior
region 1370 of the tubular member 1310 below the expandable mandrel 1305. The
material 1380 then passes from the interior region 1370 into the fluid passage 1330. The
material 13 80 then exits the apparatus 13 00 via the fluid passage 13 35 and fills the annular
region 1390 between the exterior of the tubular member 13 10 and the interior wall of the
15 new section 1230 of the wellbore 1200. Continued pumping of the material 1380 causes
the material 1380 to fill up at least a portion of the annular region 1390.
The material 1380 may be pumped into the annular region 1390 at pressures and
flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min (0
to 344.738 bar and 0 to 5618.12 litres/minute) respectively. In a preferred embodiment,
20 the material 1380 is pumped into the annular region 1390 at pressures and flow rates
ranging from about 0 to 5000 psi and 0 to 1,500 gallons/min (0 to 344.738 bar and 0 to
561 8. 12 litres/minute), respectively, in order to optimally fill the annular region between
the tubular member 1310 and the new section 1230 of the wellbore 1200 with the
hardenable fluidic sealing material 1380.
25 The hardenable fluidic sealing material 1380 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such as, for
example, slag mix, cement or epoxy. In a preferred embodiment, the hardenable fluidic
sealing material 1380 comprises blended cements designed specifically for the well
section being drilled and available from Halliburton Energy Services in order to optimally
30 provide support for the tubular member 1310 during displacement of the material 1 380 in
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the annular region 1 390. The optimum blend of the cement is preferably determined using
conventional empirical methods.
The annular region 1390 preferably is filled with the material 1380 in sufficient
quantities to ensure that, upon radial expansion of the tubular member 13 10, the annular
5 region 1390 of the new section 1230 of the wellbore 1200 will be filled with material
1380.
As illustrated in Fig. 1 1 d, once the annular region 1 390 has been adequately filled
with material 1380, a wiper dart 1395, or other similar device, is introduced into the fluid
passage 1 320. The wiper dart 1 395 is preferably pumped through the fluid passage 1320
10 by a non hardenable fluidic material 1381. The wiper dart 1 3 95 then preferably engages
the wiper plug 1350.
As illustrated in Fig. 1 1 e, in a preferred embodiment, engagement of the wiper dart
1395 with the wiper plug 1350 causes the wiper plug 1350 to decouple from the mandrel
1305. The wiper dart 1395 and wiper plug 1350 then preferably will lodge in the fluid
15 passage 1330, thereby blocking fluid flow through the fluid passage 1330, and fluidicly
isolating the interior region 1370 of the tubular member 1310 from the annular region
1390. In a preferred embodiment, the non hardenable fluidic material 1381 is then
pumped into the interior region 1 370 causing the interior region 1 370 to pressurize. Once
the interior region 1370 becomes sufficiently pressurized, the tubular member 1310 is
20 extruded off of the expandable mandrel 1305. During the extrusion process, the
expandable mandrel 1305 is raised out of the expanded portion of the tubular member
1310 by the support member 1345.
The wiper dart 1 395 is preferably placed into the fluid passage 1 320 by introducing
the wiper dart 1395 into the fluid passage 1320 at a surface location in a conventional
25 manner. The wiper dart 1395 may comprise any number of conventional commercially
available devices from plugging a fluid passage such as, for example, Multiple Stage
Cementer latch-down plugs, Omega latch-down plugs or three wiper latch-down plug/dart
modified in accordance with the teachings of the present disclosure. In a preferred
embodiment, the wiper dart 1395 comprises a three wiper latch-down plug modified to
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latch and seal in the Multiple Stage Cementer latch down plug 1350. The three wiper
latch-down plug is available from Halliburton Energy Services in Dallas, TX.
After blocking the fluid passage 1330 using the wiper plug 1330 and wiper dart
1395, the non hardenable fluidic material 1381 may be pumped into the interior region
5 1370 at pressures and flow rates ranging, for example, from approximately 0 to 5000 psi
and 0 to 1,500 gallons/min (0 to 344.738 bar and 0 to 5618.12 litres/minute) in order to
optimally extrude the tubular member 13 10 off of the mandrel 1 305. In this manner, the
amount of hardenable fluidic material within the interior of the tubular member 1310 is
minimized.
10 In a preferred embodiment, after blocking the fluid passage 1330, the non
hardenable fluidic material 1381 is preferably pumped into the interior region 1370 at
pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to 3,000
gallons/min (34.47 to 620.53 bar and 151.42 to 11356.24 litres/minute) in order to
optimally provide operating pressures to maintain the expansion process at rates sufficient
15 to permit adjustments to be made in operating parameters during the extrusion process.
For typical tubular members 1310, the extrusion of the tubular member 1310 off
of the expandable mandrel 1305 will begin when the pressure of the interior region 1370
reaches, for example, approximately (34.47 to 620.53 bar). In a preferred embodiment,
the extrusion of the tubular member 1 3 1 0 off of the expandable mandrel 1 3 05 is a function
20 of the tubular member diameter, wall thickness of the tubular member, geometry of the
mandrel, the type of lubricant, the composition of the shoe and tubular member, and the
yield strength of the tubular member. The optimum flow rate and operating pressures are
preferably determined using conventional empirical methods.
During the extrusion process, the expandable mandrel 1305 may be raised out of
25 the expanded portion of the tubular member 1310 at rates ranging, for example, from
about 0 to 5 ft/sec (0 to 1.524 metres). In a preferred embodiment, during the extrusion
process, the expandable mandrel 1305 may be raised out of the expanded portion of the
tubular member 1 3 1 0 at rates ranging from about 0 to 2 ft/sec (0 to 0.6096 metres) in order
to optimally provide an efficient process, optimally permit operator adjustment of
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operation parameters, and ensure optimal completion of the extrusion process before
curing of the material 1380.
When the upper end portion 1355 of the tubular member 1310 is extruded off of
the expandable mandrel 1305, the outer surface of the upper end portion 1355 of the
5 tubular member 1310 will preferably contact the interior surface of the lower end portion
of the casing 1215 to form an fluid tight overlapping joint. The contact pressure of the
overlapping joint may range, for example, from approximately 50 to 20,000 psi (3.447 to
137.95 bar). In a preferred embodiment, the contact pressure of the overlapping joint
ranges from approximately 400 to 10,000 psi (27.58 to 689.476 bar) in order to optimally
10 provide contact pressure sufficient to ensure annular sealing and provide enough resistance
to withstand typical tensile and compressive loads. In a particularly preferred
embodiment, the sealing members 1340 will ensure an adequate fluidic and gaseous seal
in the overlapping joint.
In a preferred embodiment, the operating pressure and flow rate of the non
15 hardenable fluidic material 1381 is controllably ramped down when the expandable
mandrel 1305 reaches the upper end portion 1355 of the tubular member 1310. In this
manner, the sudden release of pressure caused by the complete extrusion of the tubular
member 1310 off of the expandable mandrel 1305 can be minimized. In a preferred
embodiment, the operating pressure is reduced in a substantially linear fashion from 1 00%
20 to about 10% during the end of the extrusion process beginning when the mandrel 1305
has completed approximately all but about 5 feet (1 .524 metres) of the extrusion process.
Alternatively, or in combination, a shock absorber is provided in the support
member 1345 in order to absorb the shock caused by the sudden release of pressure.
Alternatively, or in combination, a mandrel catching structure is provided in the
25 upper end portion 1 355 of the tubular member 1 3 1 0 in order to catch or at least decelerate
the mandrel 1305.
Once the extrusion process is completed, the expandable mandrel 1 305 is removed
from the wellbore 1 200. In a preferred embodiment, either before or after the removal of
the expandable mandrel 1305, the integrity of the fluidic seal of the overlapping joint
30 between the upper portion 1355 of the tubular member 13 10 and the lower portion of the
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casing 1215 is tested using conventional methods. If the fluidic seal of the overlapping
joint between the upper portion 1355 of the tubular member 1310 and the lower portion
of the casing 1 2 1 5 is satisfactory, then the uncured portion of the material 1 380 within the
expanded tubular member 13 10 is then removed in a conventional manner. The material
5 1380 within the annular region 1390 is then allowed to cure.
As illustrated in Fig. 1 1 f, preferably any remaining cured material 1380 within the
interior of the expanded tubular member 13 10 is then removed in a conventional manner
using a conventional drill string. The resulting new section of casing 1400 includes the
expanded tubular member 1310 and an outer annular layer 1405 of cured material 305.
10 The bottom portion of the apparatus 1 300 comprising the shoe 1315 may then be removed
by drilling out the shoe 1315 using conventional drilling methods.
Referring now to Figs. 12 and 13, a preferred embodiment of a wellhead system
1500 formed using one or more of the apparatus and processes described above with
reference to Figs. 1 - 1 1 f will be described. The wellhead system 1 500 preferably includes
15 a conventional Christmas tree/drilling spool assembly 1505, a thick wall casing 15 1 0, an
annular body of cement 1 5 1 5, an outer casing 1 520, an annular body of cement 1 525, an
intermediate casing 1530, and an inner casing 1535.
The Christmas tree/drilling spool assembly 1505 may comprise any number of
conventional Christmas tree/drilling spool assemblies such as, for example, the SS-15
20 Subsea Wellhead System, Spool Tree Subsea Production System or the Compact Wellhead
System available from suppliers such as Dril-Quip, Cameron or Breda, modified in
accordance with the teachings of the present disclosure. The drilling spool assembly 1 505
is preferably operably coupled to the thick wall casing 1510 and/or the outer casing 1 520.
The assembly 1505 may be coupled to the thick wall casing 1510 and/or outer casing
25 1520, for example, by welding, a threaded connection or made from single stock. In a
preferred embodiment, the assembly 1 505 is coupled to the thick wall casing 1510 and/or
outer casing 1520 by welding.
The thick wall casing 15 10 is positioned in the upper end of a wellbore 1540. In
a preferred embodiment, at least a portion of the thick wall casing 1510 extends above the
30 surface 1545 in order to optimally provide easy access and attachment to the Christmas
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tree/drilling spool assembly 1505. The thick wall casing 1510 is preferably coupled to the
Christmas tree/drilling spool assembly 1505, the annular body of cement 1515, and the
outer casing 1520.
The thick wall casing 1510 may comprise any number of conventional
5 commercially available high strength wellbore casings such as, for example, Oilfield
Country Tubular Goods, titanium tubing or stainless steel tubing. In a preferred
embodiment, the thick wall casing 1510 comprises Oilfield Country Tubular Goods
available from various foreign and domestic steel mills. In a preferred embodiment, the
thick wail casing 1510 has a yield strength of about 40,000 to 135,000 psi (2757.90 to
10 9307.92 bar) in order to optimally provide maximum burst, collapse, and tensile strengths.
In a preferred embodiment, the thick wall casing 1 5 1 0 has a failure strength in excess of
about 5,000 to 20,000 psi (344.737 to 1,378.951 bar) in order to optimally provide
maximum operating capacity and resistance to degradation of capacity after being drilled
through for an extended time period.
15 The annular body of cement 1515 provides support for the thick wall casing 1510.
The annular body of cement 1515 may be provided using any number of conventional
processes for forming an annular body of cement in a wellbore. The annular body of
cement 1515 may comprise any number of conventional cement mixtures.
The outer casing 1 520 is coupled to the thick wall casing 1 5 10. The outer casing
20 1 520 may be fabricated from any number of conventional commercially available tubular
members modified in accordance with the teachings of the present disclosure. In a
preferred embodiment, the outer casing 1 520 comprises any one of the expandable tubular
members described above with reference to Figs. 1-1 1 f.
In a preferred embodiment, the outer casing 1520 is coupled to the thick wall
25 casing 1 5 1 0 by expanding the outer casing 1 520 into contact with at least a portion of the
interior surface of the thick wall casing 1510 using any one of the embodiments of the
processes and apparatus described above with reference to Figs. 1-1 If. In an alternative
embodiment, substantially all of the overlap of the outer casing 1 520 with the thick wall
casing 1510 contacts with the interior surface of the thick wall casing 1510.
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The contact pressure of the interface between the outer casing 1 520 and the thick
wall casing 1510 may range, for example, from about 500 to 10,000 psi (34.47 to 689.48
bar). In a preferred embodiment, the contact pressure between the outer casing 1 520 and
the thick wall casing 1510 ranges from about 500 to 10,000 psi (34.47 to 689.48 bar) in
5 order to optimally activate the pressure activated sealing members and to ensure that the
overlapping joint will optimally withstand typical extremes of tensile and compressive
loads that are experienced during drilling and production operations. As illustrated in
Fig. 13, in a particularly preferred embodiment, the upper end of the outer casing 1520
includes one or more sealing members 1550 that provide a gaseous and fluidic seal
10 between the expanded outer casing 1520 and the interior wall of the thick wall casing
1510. The sealing members 1550 may comprise any number of conventional
commercially available seals such as, for example, lead, plastic, rubber, Teflon (RTM) or
epoxy, modified in accordance with the teachings of the present disclosure. In a preferred
embodiment, the sealing members 1550 comprise seals molded from StrataLock epoxy
15 available from Halliburton Energy Services in order to optimally provide an hydraulic seal
and a load bearing interference fit between the tubular members. In a preferred
embodiment, the contact pressure of the interface between the thick wall casing 1510 and
the outer casing 1 520 ranges from about 500 to 10,000 psi (34.47 to 689.48 bar) in order
to optimally activate the sealing members 1550 and also optimally ensure that the joint
20 will withstand the typical operating extremes of tensile and compressive loads during
drilling and production operations.
In an alternative preferred embodiment, the outer casing 1 520 and the thick walled
casing 1510 are combined in one unitary member.
The annular body of cement 1525 provides support for the outer casing 1520. In
25 a preferred embodiment, the annular body of cement 1525 is provided using any one of
the embodiments of the apparatus and processes described above with reference to Figs.
1-1 If.
The intermediate casing 1 530 may be coupled to the outer casing 1 520 or the thick
wall casing 1510. In a preferred embodiment, the intermediate casing 1 530 is coupled to
30 the thick wall casing 1510. The intermediate casing 1530 may be fabricated from any
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number of conventional commercially available tubular members modified in accordance
with the teachings of the present disclosure. In a preferred embodiment, the intermediate
casing 1 530 comprises any one of the expandable tubular members described above with
reference to Figs, l-l If.
5 In a preferred embodiment, the intermediate casing 1530 is coupled to the thick
wall casing 1510 by expanding at least a portion of the intermediate casing 1530 into
contact with the interior surface of the thick wall casing 1510 using any one of the
processes and apparatus described above with reference to Figs. 1-1 If In an alternative
preferred embodiment, the entire length of the overlap of the intermediate casing 1530
10 with the thick wall casing 1510 contacts the inner surface of the thick wall casing 1510.
The contact pressure of the interface between the intermediate casing 1 530 and the thick
wall casing 1510 may range, for example from about 500 to 10,000 psi (34.47 to 689.48
bar). In a preferred embodiment, the contact pressure between the intermediate casing
1 530 and the thick wall casing 1510 ranges from about 500 to 1 0,000 psi (34.47 to 689.48
15 bar) in order to optimally activate the pressure activated sealing members and to optimally
ensure that the joint will withstand typical operating extremes of tensile and compressive
loads experienced during drilling and production operations.
As illustrated in Fig. 1 3, in a particularly preferred embodiment, the upper end of
the intermediate casing 1530 includes one or more sealing members 1560 that provide a
20 gaseous and fluidic seal between the expanded end of the intermediate casing 1530 and
the interior wall of the thick wall casing 1510. The sealing members 1 560 may comprise
any number of conventional commercially available seals such as, for example, plastic,
lead, rubber, Teflon (RTM) or epoxy, modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the sealing members 1 560 comprise seals
25 molded from StrataLock epoxy available from Halliburton Energy Services in order to
optimally provide a hydraulic seal and a load bearing interference fit between the tubular
members.
In a preferred embodiment, the contact pressure of the interface between the
expanded end of the intermediate casing 1 530 and the thick wall casing 1510 ranges from
30 about 500 to 10,000 psi (34.47 to 689.48 bar) in order to optimally activate the sealing
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members 1560 and also optimally ensure that the joint will withstand typical operating
extremes of tensile and compressive loads that are experienced during drilling and
production operations.
The inner casing 1 535 may be coupled to the outer casing 1 520 or the thick wall
5 casing 1510. In a preferred embodiment, the inner casing 153 5 is coupled to the thick wall
casing 1510. The inner casing 1 535 may be fabricated from any number of conventional
commercially available tubular members modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the inner casing 1 535 comprises any one
of the expandable tubular members described above with reference to Figs. 1 -1 If.
10 In a preferred embodiment, the inner casing 1535 is coupled to the outer casing
1 520 by expanding at least a portion of the inner casing 1 535 into contact with the interior
surface of the thick wall casing 1510 using any one of the processes and apparatus
described above with reference to Figs. 1 - 1 1 f. In an alternative preferred embodiment,
the entire length of the overlap of the inner casing 1535 with the thick wall casing 1510
15 and intermediate casing 1 530 contacts the inner surfaces of the thick wall casing 1510 and
intermediate casing 1 530. The contact pressure of the interface between the inner casing
1535 and the thick wall casing 1510 may range, for example from about 500 to 1 0,000 psi
(34.47 to 689,48 bar). In a preferred embodiment, the contact pressure between the inner
casing 1535 and the thick wall casing 1510 ranges from about 500 to 10,000 psi (34.47
20 to 689.48 bar) in order to optimally activate the pressure activated sealing members and
to ensure that the joint will withstand typical extremes of tensile and compressive loads
that are commonly experienced during drilling and production operations.
As illustrated in Fig. 1 3, in a particularly preferred embodiment, the upper end of
the inner casing 1 535 includes one or more sealing members 1 570 that provide a gaseous
25 and fluidic seal between the expanded end of the inner casing 1535 and the interior wall
of the thick wall casing 1510. The sealing members 1570 may comprise any number of
conventional commercially available seals such as, for example, lead, plastic, rubber,
Teflon (RTM) or epoxy, modified in accordance with the teachings of the present
disclosure. In a preferred embodiment, the sealing members 1 570 comprise seals molded
30 from StrataLock epoxy available from Halliburton Energy Services in order to optimally
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provide an hydraulic seal and a load bearing interference fit. In a preferred embodiment,
the contact pressure of the interface between the expanded end of the inner casing 1535
and the thick wall casing 1510 ranges from about 500 to 10,000 psi (34.47 to 689.48 bar)
in order to optimally activate the sealing members 1570 and also to optimally ensure that
5 the joint will withstand typical operating extremes of tensile and compressive loads that
are experienced during drilling and production operations.
In an alternative embodiment, the inner casings, 1520, 1530 and 1535, may be
coupled to a previously positioned tubular member that is in turn coupled to the outer
casing 1510. More generally, the present preferred embodiments may be used to form a
10 concentric arrangement of tubular members.
Referring now to Figures 14a, 14b, 14c, 14d, 14eand 14f, a preferred embodiment
of a method and apparatus for forming a mono-diameter well casing within a subterranean
formation will now be described.
As illustrated in Fig. 14a, a wellbore 1 600 is positioned in a subterranean formation
15 1605. A first section of casing 1610 is formed in die wellbore 1600. The first section of
casing 1610 includes an annular outer body of cement 161 5 and a tubular section of casing
1620. The first section of casing 1610 may be formed in the wellbore 1600 using
conventional methods and apparatus. In a preferred embodiment, the first section of
casing 1610 is formed using one or more of the methods and apparatus described above
20 with reference to Figs. 1-13 or below with reference to Figs. 14b- 17b.
The annular body of cement 1615 may comprise any number of conventional
commercially available cement, or other load bearing, compositions. Alternatively, the
body of cement 1615 may be omitted or replaced with an epoxy mixture.
The tubular section of casing 1620 preferably includes an upper end 1625 and a
25 lower end 1630. Preferably, the lower end 1625 of the tubular section of casing 1620
includes an outer annular recess 1635 extending from the lower end 1630 of the tubular
section of casing 1 620. In this manner, the lower end 1 625 of the tubular section of casing
1620 includes a thin walled section 1640. In a preferred embodiment, an annular body
1645 of a compressible material is coupled to and at least partially positioned within the
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outer annular recess 1635. In this manner, the body of compressible material 1645
surrounds at least a portion of the thin walled section 1640.
The tubular section of casing 1620 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield country
5 tubular goods, stainless steel, automotive grade steel, carbon steel, low alloy steel,
fiberglass or plastics. In a preferred embodiment, the tubular section of casing 1620 is
fabricated from oilfield country tubular goods available from various foreign and domestic
steel mills. The wall thickness of the thin walled section 1640 may range from about
0.125 to 1.5 inches (0.3175 to 3.81 centimetres). In a preferred embodiment, the wall
10 thickness of the thin walled section 1640 ranges from 0.25 to 1.0 inches (0.635 to 2.54
centimetres) in order to optimally provide burst strength for typical operational conditions
while also minimizing resistance to radial expansion. The axial length of the thin walled
section 1640 may range from about 120 to 2400 inches (304.8 to 6,096 centimetres). In
a preferred embodiment, the axial length of the thin walled section 1 640 ranges from about
15 240 to 480 inches (609.6 to 1219.2 centimetres).
The annular body of compressible material 1 645 helps to minimize the radial force
required to expand the tubular casing 1620 in the overlap with the tubular member 1715,
helps to create a fluidic seal in the overlap with the tubular member 1715, and helps to
create an interference fit sufficient to permit the tubular member 1 7 1 5 to be supported by
20 the tubular casing 1620. The annular body of compressible material 1645 may comprise
any number of commercially available compressible materials such as, for example,
epoxy, rubber, Teflon (RTM), plastics or lead tubes. In a preferred embodiment, the
annular body of compressible material 1645 comprises StrataLock epoxy available from
Halliburton Energy Services in order to optimally provide an hydraulic seal in the
25 overlapped joint while also having compliance to thereby minimize the radial force
required to expand the tubular casing. The wall thickness of the annular body of
compressible material 1645 may range from about 0.05 to 0.75 inches (0.127 to 1.905
centimetres). In a preferred embodiment, the wall thickness of the annular body of
compressible material 1645 ranges from about 0.1 to 0.5 inches (0.254 to 0.127
30 centimetres) in order to optimally provide a large compressible zone, minimize the radial
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forces required to expand the tubular casing, provide thickness for casing strings to
provide contact with the inner surface of the wellbore upon radial expansion, and provide
an hydraulic seal.
As illustrated in Fig. 14b, in order to extend the wellbore 1600 into the
5 subterranean formation 1605, a drill string is used in a well known manner to drill out
material from the subterranean formation 1605 to form a new wellbore section 1650. The
diameter of the new section 1650 is preferably equal to or greater than the inner diameter
of the tubular section of casing 1620.
As illustrated in Fig. 1 4c, apreferred embodiment of an apparatus 1 700 for forming
10a mono-diameter wellbore casing in a subterranean formation is then positioned in the new
section 1650 of the wellbore 1600; The apparatus 1700 preferably includes a support
member 1705, an expandable mandrel or pig 1710, a tubular member 1715,ashoe 1720,
slips 1725, a fluid passage 1730, one or more fluid passages 1735, a fluid passage 1740,
a first compressible annular body 1 745, a second compressible annular body 1 750, and a
15 pressure chamber 1755.
The support member 1705 supports the apparatus 1700 within the wellbore 1600.
The support member 1 705 is coupled to the mandrel 1710, the tubular member 1 7 1 5, the
shoe 1720, and the slips 1725. The support member 1075 preferably comprises a
substantially hollow tubular member. The fluid passage 1730 is positioned within the
20 support member 1705. The fluid passages 1735 fluidicly couple the fluid passage 1730
with the pressure chamber 1755. The fluid passage 1740 fluidicly couples the fluid
passage 1730 with the region outside of the apparatus 1700.
The support member 1705 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country tubular goods,
25 stainless steel, low alloy steel, carbon steel, 13 chromium steel, fiberglass, or other high
strength materials. In a preferred embodiment, the support member 1705 is fabricated
from oilfield country tubular goods available from various foreign and domestic steel mills
in order to optimally provide operational strength and faciliate the use of other standard
oil exploration handling equipment. In a preferred embodiment, at least a portion of the
30 support member 1705 comprises coiled tubing or a drill pipe. In a particularly preferred
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embodiment, the support member 1705 includes a load shoulder 1 820 for supporting the
mandrel 1710 when the pressure chamber 1755 is unpressurized.
The mandrel 1710 is supported by and slidingly coupled to the support member
1 705 and the shoe 1 720. The mandrel 1710 preferably includes an upper portion 1 760 and
5 a lower portion 1765. Preferably, the upper portion 1760 of the mandrel 1710 and the
support member 1 705 together define the pressure chamber 1 755. Preferably, the lower
portion 1765 of the mandrel 1710 includes an expansion member 1770 for radially
expanding the tubular member 1715.
In a preferred embodiment, the upper portion 1760 of the mandrel 1710 includes
10 a tubular member 1775 having an inner diameter greater than an outer diameter of the
support member 1 705. In this manner, an annular pressure chamber 1 755 is defined by
and positioned between the tubular member 1775 and the support member 1705. The top
1 780 of the tubular member 1 775 preferably includes a bearing and a seal for sealing and
supporting the top 1780 of the tubular member 1775 against the outer surface of the
15 supportmemberl705. The bottom 1785 of the tubular member 1775 preferably includes
a bearing and seal for sealing and supporting the bottom 1785 of the tubular member 1775
against the outer surface of the support member 1705 or shoe 1720. In this manner, the
mandrel 1710 moves in an axial direction upon the pressurization of the pressure chamber
1755.
20 The lower portion 1765 of the mandrel 1710 preferably includes an expansion
member 1770 for radially expanding the tubular member 1715 during the pressurization
of the pressure chamber 1755. In a preferred embodiment, the expansion member is
expandible in the radial direction. In a preferred embodiment, the inner surface of the
lower portion 1765 of the mandrel 1710 mates with and slides with respect to the outer
25 surface of the shoe 1720. The outer diameter of the expansion member 1770 may range
from about 90 to 100 % of the inner diameter of the tubular casing 1620. In a preferred
embodiment, the outer diameter of the expansion member 1770 ranges from about 95 to
99 % of the inner diameter of the tubular casing 1 620. The expansion member 1770 may
be fabricated from any number of conventional commercially available materials such as,
30 for example, machine tool steel, ceramics, tungsten carbide, titanium or other high
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strength alloys. In a preferred embodiment, the expansion member 1770 is fabricated
from D2 machine tool steel in order to optimally provide high strength and abrasion
resistance.
The tubular member 1 7 1 5 is coupled to and supported by the support member 1 705
5 and slips 1725. The tubular member 1715 includes an upper portion 1790 and a lower
portion 1795.
The upper portion 1 790 of the tubular member 1715 preferably includes an inner
annular recess 1800 that extends from the upper portion 1790ofthe tubular member 1715.
In this manner, at least a portion of the upper portion 1790 of the tubular member 1715
10 includes a thin walled section 1805. The first compressible annular member 1745 is
preferably coupled to and supported by the outer surface of the upper portion 1 790 of the
tubular member 1715 in opposing relation to the thin wall section 1805.
The lower portion 1 795 of the tubular member 1715 preferably includes an outer
annular recess 1810 that extends from the lower portion 1 790 of the tubular member 1715.
15 In this manner, at least a portion of the lower portion 1795 of the tubular member 1715
includes a thin walled section 1815. The second compressible annular member 1750 is
coupled to and at least partially supported within the outer annular recess 1810 of the
upper portion 1790 of the tubular member 1715 in opposing relation to the thin wall
section 1815.
20 The tubular member 1715 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country tubular goods,
stainless steel, low alloy steel, carbon steel, automotive grade steel, fiberglass, 1 3 chrome
steel, other high strength material, or high strength plastics. In a preferred embodiment,
the tubular member 1 7 1 5 is fabricated from oilfield country tubular goods available from
25 various foreign and domestic steel mills in orderto optimally provide operational strength.
The shoe 1 720 is supported by and coupled to the support member 1 705. The shoe
1720 preferably comprises a substantially hollow tubular member. In a preferred
embodiment, the wall thickness of the shoe 1720 is greater than the wall thickness of the
support member 1 705 in order to optimally provide increased radial support to the
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mandrel 1710. The shoe 1720 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country tubular goods,
stainless steel, automotive grade steel, low alloy steel, carbon steel, or high strength
plastics. In a preferred embodiment, the shoe 1720 is fabricated from oilfield country
5 tubular goods available from various foreign and domestic steel mills in order to optimally
provide matching operational strength throughout the apparatus.
The slips 1725 are coupled to and supported by the support member 1705. The
slips 1 725 removably support the tubular member 1715. In this manner, during the radial
expansion ofthe tubular member 1715, the slips 1725 help to maintain the tubular member
10 1 7 1 5 in a substantially stationary position by preventing upward movement ofthe tubular
member 1715.
The slips 1 725 may comprise any number of conventional commercially available
slips such as, for example, RTTS packer tungsten carbide mechanical slips, RTTS packer
wicker type mechanical slips, or Model 3L retrievable bridge plug tungsten carbide upper
15 mechanical slips. In a preferred embodiment, the slips 1725 comprise RTTS packer
tungsten carbide mechanical slips available from Halliburton Energy Services. In a
preferred embodiment, the slips 1725 are adapted to support axial forces ranging from
about 0 to 750,000 lbf (0 to 51,710.b7 bar).
The fluid passage 1730 conveys fluidic materials from a surface location into the
20 interior ofthe support member 1 705, the pressure chamber 1 755, and the region exterior
ofthe apparatus 1700. The fluid passage 1730 is fludicly coupled to the pressure chamber
1755 by the fluid passages 1735. The fluid passage 1730 is fluidicly coupled to the region
exterior to the apparatus 1700 by the fluid passage 1740.
In a preferred embodiment, the fluid passage 1730 is adapted to convey fluidic
25 materials such as, for example, cement, epoxy, drilling muds, slag mix, water or drilling
gasses. In a preferred embodiment, the fluid passage 1730 is adapted to convey fluidic
materials at flow rate and pressures ranging from about 0 to 3,000 gallons/minute and 0
to 9,000 psi. (0 to 11356.24 litres/minute and 0 to 620.528 bar) in order to optimally
provide flow rates and operational pressures for the radial expansion processes.
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The fluid passages 1 735 convey fluidic material from the fluid passage 1 730 to the
pressure chamber 1755. In a preferred embodiment, the fluid passage 1 735 is adapted to
convey fluidic materials such as, for example, cement, epoxy, drilling muds, water or
drilling gasses. In a preferred embodiment, the fluid passage 1 735 is adapted to convey
5 fluidic materials at flow rate and pressures ranging from about 0 to 500 gal lons/minute and
(0 to 620, 528 bar), in order to optimally provide operating pressures and flow rates for the
various expansion processes.
The fluid passage 1740 conveys fluidic materials from the fluid passage 1730 to
the region exterior to the apparatus 1700. In a preferred embodiment, the fluid passage
10 1 740 is adapted to convey fluidic materials such as, for example, cement, epoxy, drilling
muds, water or drilling gasses. In a preferred embodiment, the fluid passage 1740 is
adapted to convey fluidic materials at flow rate and pressures ranging from about 0 to
3,000 gallons/minute and 0 to 9,000 psi. (0 to 1 1356.24 litres/minute and 0 to 620.528 bar)
in order to optimally provide operating pressures and flow rates for the various radial
15 expansion processes.
In a preferred embodiment, the fluid passage 1740 is adapted to receive a plug or
other similar device for sealing the fluid passage 1740. In this manner, the pressure
chamber 1 755 may be pressurized.
The first compressible annular body 1745 is coupled to and supported by an
20 exterior surface of the upper portion 1790 of the tubular member 1715. In a preferred
embodiment, the first compressible annular body 1745 is positioned in opposing relation
to the thin walled section 1 805 of the tubular member 1715.
The first compressible annular body 1745 helps to minimize the radial force
required to expand the tubular member 1 7 1 5 in the overlap with the tubular casing 1620,
25 helps to create a fluidic seal in the overlap with the tubular casing 1620, and helps to
create an interference fit sufficient to permit the tubular member 1 7 1 5 to be supported by
the tubular casing 1620. The first compressible annular body 1745 may comprise any
number of commercially available compressible materials such as, for example, epoxy,
rubber, Teflon (RTM), plastics, or hollow lead tubes. In a preferred embodiment, the first
30 compressible annular body 1 745 comprises StrataLock epoxy available from Halliburton
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Energy Services in order to optimally provide an hydraulic seal, and compressibility to
minimize the radial expansion force.
The wall thickness of the first compressible annular body 1745 may range from
about 0.05 to 0.75 inches (0.127 to 1.905 centimetres). In a preferred embodiment, the
5 wall thickness of the first compressible annular body 1 745 ranges from about 0. 1 to 0.5
inches (0.254 to 0. 127 centimetres) in order to optimally ( 1 ) provide a large compressible
zone, (2) minimize the required radial expansion force, (3) transfer the radial force to the
tubular casings. As a result, in a preferred embodiment, overall the outer diameter of the
tubular member 1715 is approximately equal to the overall inner diameter of the tubular
10 member 1620.
The second compressible annular body 1750 is coupled to and at least partially
supported within the outer annular recess 1810ofthetubularmemberl7l5. Inapreferred
embodiment, the second compressible annular body 1750 is positioned in opposing
relation to the thin walled section 1815 of the tubular member 1715.
15 The second compressible annular body 1750 helps to minimize the radial force
required to expand the tubular member 1 7 1 5 in the overlap with another tubular member,
helps to create a fluidic seal in the overlap of the tubular member 1715 with another
tubular member, and helps to create an interference fit sufficient to permit another tubular
member to be supported by the tubular member 1715. The second compressible annular
20 body 1 750 may comprise any number of commercially available compressible materials
such as, for example, epoxy, rubber, Teflon (RTM), plastics or hollow lead tubing. In a
preferred embodiment, the first compressible annular body 1750 comprises StrataLock
epoxy available from Halliburton Energy Services in order to optimally provide an
hydraulic seal in the overlapped joint, and compressibility that minimizes the radial
25 expansion force.
The wall thickness of the second compressible annular body 1 750 may range from
about 0.05 to 0.75 inches (0. 1 27 to 1 .905 centimetres). In a preferred embodiment, the
wall thickness of the second compressible annular body 1 750 ranges from about 0. 1 to 0.5
inches (0.254 to 0.127 centimetres) in order to optimally provide a large compressible
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zone, and minimize the radial force required to expand the tubular member 1715 during
subsequent radial expansion operations.
In an alternative embodiment, the outside diameter of the second compressible
annular body 1 750 is adapted to provide a seal against the surrounding formation thereby
5 eliminating the need for an outer annular body of cement.
The pressure chamber 1755 is fludicly coupled to the fluid passage 1730 by the
fluid passages 1735. The pressure chamber 1755 is preferably adapted to receive fluidic
materials such as, for example, drilling muds, water or drilling gases. In a preferred
embodiment, the pressure chamber 1 755 is adapted to receive fluidic materials at flow rate
10 and pressures ranging from about 0 to 500 gallons/minute and 0 to 9,000 psi (3.785
litres/minute and 0 to 620.528 bar), in order to optimally provide expansion pressure. In
a preferred embodiment, during pressurization of the pressure chamber 1755, the operating
pressure of the pressure chamber ranges from about 0 to 5,000 psi in order to optimally
provide expansion pressure while minimizing the possibility of a catastrophic failure due
15 to over pressurization.
As illustrated in Fig. 14d, the apparatus 1700 is preferably positioned in the
wcllbore 1600 with the tubular member 1715 positioned in an overlapping relationship
with the tubular casing 1620. In a particularly preferred embodiment, the thin wall
sections, 1640 and 1805, of the tubular casing 1620 and tubular member 1725 are
20 positioned in opposing overlapping relation. In this manner, the radial expansion of the
tubular member 1725 will compress the thin wall sections, 1640 and 1805, and annular
compressible members, 1645 and 1745, into intimate contact.
Afterpositioning ofthe apparatus 1700,afluidic material 1825 is then pumped into
the fluid passage 1730. The fluidic material 1825 may comprise any number of
25 conventional commercially available materials such as, for example, water, drilling mud,
drilling gases, cement or epoxy. In a preferred embodiment, the fluidic material 1825
comprises a hardenable fluidic sealing material such as, for example, cement in order to
provide an outer annular body around the expanded tubular member 1715.
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The fluidic material 1 825 may be pumped into the fluid passage 1 730 at operating
pressures and flow rates, for example, ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The fluidic material 1 825 pumped into the fluid passage 1 730 passes through the
5 fluid passage 1740 and outside of the apparatus 1700. The fluidic material 1825 fills the
annular region 1830 between the outside of the apparatus 1700 and the interior walls of
the wellbore 1600.
As illustrated in Fig. 14e, a plug 1835 is then introduced into the fluid passage
1730. The plug 1835 lodges in the inlet to the fluid passage 1740 fluidicly isolating and
10 blocking off the fluid passage 1 730.
A fluidic material 1 840 is then pumped into the fluid passage 1730. The fluidic
material 1 840 may comprise any number of conventional commercially available materials
such as, for example, water, drilling mud or drilling gases. In a preferred embodiment, the
fluidic material 1825 comprises a non-hardenable fluidic material such as, for example,
15 drilling mud or drilling gases in order to optimally provide pressurization of the pressure
chamber 1755.
The fluidic material 1 840 may be pumped into the fluid passage 1 730 at operating
pressures and flow rates ranging, for example, from about 0 to 9,000 psi and 0 to 500
gallons/minute (0 to 620.528 bar and3.785 litres/minute). In a preferred embodiment, the
20 fluidic material 1840 is pumped into the fluid passage 1730 at operating pressures and
flow rates ranging from about 500 to 5,000 psi and 0 to 500 gallons/minute (34.47 to
344.737 bar and 0 to 1892.705 litres/minute) to in order to optimally provide operating
pressures and flow rates for radial expansion.
The fluidic material 1840 pumped into the fluid passage 1730 passes through the
25 fluid passages 1735 and into the pressure chamber 1755. Continued pumping of the
fluidic material 1840 pressurizes the pressure chamber 1755. The pressurization of the
pressure chamber 1 755 causes the mandrel 1 71 0 to move relative to the support member
1705 in the direction indicated by the arrows 1845. In this manner, the mandrel 1710will
cause the tubular member 1715 to expand in the radial direction.
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During the radial expansion process, the tubular member 1 71 5 is prevented from
moving in an upward direction by the slips 1725. A length of the tubular member 1715
is then expanded in the radial direction through the pressurization of the pressure chamber
1755. The length of the tubular member 1715 that is expanded during the expansion
5 process will be proportional to the stroke length of the mandrel 1710. Upon the
completion of a stroke, the operating pressure of the pressure chamber 1755 is then
reduced and the mandrel 1710 drops to it rest position with the tubular member 1715
supported by the mandrel 1715. The position of the support member 1705 may be
adjusted throughout the radial expansion process in order to maintain the overlapping
10 relationship between the thin walled sections, 1640 and 1805, of the tubular casing 1620
and tubular member 1715. The stroking of the mandrel 1710 is then repeated, as
necessary, until the thin walled section 1 805 of the tubular member 1 7 1 5 is expanded into
the thin walled section 1640 of the tubular casing 1620.
In a preferred embodiment, during the final stroke of the mandrel 1710, the slips
15 1725 are positioned as close as possible to the thin walled section 1805 of the tubular
member 1715 in order minimize slippage between the tubular member 1715 and tubular
casing 1620 at the end of the radial expansion process. Alternatively, or in addition, the
outside diameter of the first compressive annular member 1745 is selected to ensure
sufficient interference fit with the tubular casing 1 620 to prevent axial displacement of the
20 tubular member 1715 during the final stroke. Alternatively, or in addition, the outside
diameter of the second compressive annular body 1750 is large enough to provide an
interference fit with the inside walls of the wellbore 1 600 at an earlier point in the radial
expansion process so as to prevent further axial displacement of the tubular member 1715.
In this final alternative, the interference fit is preferably selected to permit expansion of
25 the tubular member 1 7 1 5 by pulling the mandrel 1 7 1 0 out of the wellbore 1 600, without
having to pressurize the pressure chamber 1755.
During the radial expansion process, the pressurized areas of the apparatus 1700
are limited to the fluid passages 1730 within the support member 1705 and the pressure
chamber 1755 within the mandrel 1710. No fluid pressure acts directly on the tubular
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member 1715. This permits the use of operating pressures higher than the tubular member
1715 could normally withstand.
Once the tubular member 1715 has been completely expanded off of the mandrel
1710, the support member 1705 and mandrel 1710 are removed from the wellbore 1600.
5 In a preferred embodiment, the contact pressure between the deformed thin wall sections,
1640 and 1805, and compressible annular members, 1645 and 1745, ranges from about
400 to 1 0,000 psi (27.58 to 689.476 bar) in order to optimally support the tubular member
1715 using the tubular casing 1620.
In this manner, the tubular member 17 1 5 is radially expanded into contact with the
10 tubular casing 1 620 by pressurizing the interior of the fluid passage 1 730 and the pressure
chamber 1755.
As illustrated in Fig. 14f, in a preferred embodiment, once the tubular member
1715 is completely expanded in the radial direction by the mandrel 1710, the support
member 1705 and mandrel 1710 are removed from the wellbore 1600. In a preferred
15 embodiment, the annular body of hardenable fluidic material is then allowed to cure to
form a rigid outer annular body 1850. In the case where the tubular member 1715 is
slotted, the hardenable fluidic material will preferably permeate and envelop the expanded
tubular member 1715.
The resulting new section of wellbore casing 1 855 includes the expanded tubular
20 member 1715 and the rigid outer annular body 1850. The overlapping joint 1860 between
the tubular casing 1620 and the expanded tubular member 1715 includes the deformed thin
wall sections, 1640 and 1805, and the compressible annular bodies, 1645 and 1745. The
inner diameter of the resulting combined wellbore casings is substantially constant. In this
manner, a mono-diameter wellbore casing is formed. This process of expanding
25 overlapping tubular members having thin wall end portions with compressible annular
bodies into contact can be repeated for the entire length of a wellbore. In this manner, a
mono-diameter wellbore casing can be provided for thousands of feet in a subterranean
formation.
Referring now to Figures 15, 15a and 15b, an embodiment of an apparatus 1900
30 for expanding a tubular member will be described. The apparatus 1900 preferably
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includes a drillpipe 1905, an itinerstring adapter 1910, a sealing sleeve 1915, an inner
sealing mandrel 1920, an upper sealing head 1925, a lower sealing head 1930, an outer
sealing mandrel 1935, a load mandrel 1940, an expansion cone 1945, a mandrel launcher
1950, a mechanical slipbody 1955, mechanical slips 1960, drag blocks 1965, casing 1970,
5 and fluid passages 1975, 1980, 1985, and 1990.
The drillpipe 1905 is coupled to the innerstring adapter 1910. During operation
of the apparatus 1900, the drillpipe 1905 supports the apparatus 1900. The drillpipe 1905
preferably comprises a substantially hollow tubular member or members. The drillpipe
1905 may be fabricated from any number of conventional commercially available
10 materials such as, for example, oilfield country tubular drillpipe, fiberglass or coiled
tubing. In a preferred embodiment, the drillpipe 1 905 is fabricated from coiled tubing in
order to faciliate the placement of the apparatus 1900 in non-vertical wellbores. The
drillpipe 1905 may be coupled to the innerstring adapter 1910 using any number of
conventional commercially available mechanical couplings such as, for example, drillpipe
15 connectors, OCTG specialty type box and pin connectors, a ratchet-latch type connector
or a standard box by pin connector. In a preferred embodiment, the drillpipe 1905 is
removably coupled to the innerstring adapter 1910 by a drillpipe connection.
The drillpipe 1905 preferably includes a fluid passage 1975 that is adapted to
convey fluidic materials from a surface location into the fluid passage 1 980. In a preferred
20 embodiment, the fluid passage 1975 is adapted to convey fluidic materials such as, for
example, cement, drilling mud, epoxy or lubricants at operating pressures and flow rates
ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528 bar and 0
to 1 1356.24 litres/minute).
The innerstring adapter 1910 is coupled to the drill string 1905 and the sealing
25 sleeve 1915. The innerstring adapter 1910 preferably comprises a substantially hollow
tubular member or members. The innerstring adapter 1910 may be fabricated from any
number of conventional commercially available materials such as, for example, oil country
tubular goods, low alloy steel, carbon steel, stainless steel or other high strength materials.
In a preferred embodiment, the innerstring adapter 1 9 1 0 is fabricated from oilfield country
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tubular goods in order to optimally provide mechanical properties that closely match those
of the drill string 1905.
The innerstring adapter 1910 may be coupled to the drill string 1905 using any
number of conventional commercially available mechanical couplings such as, for
5 example, drillpipe connectors, oilfield country tubular goods specialty type threaded
connectors, ratchet-latch type stab in connector, or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 1 9 1 0 is removably coupled to the drill pipe
1905 by a drillpipe connection. The innerstring adapter 1910 may be coupled to the
sealing sleeve 1915 using anynumber of conventional commercially available mechanical
10 couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connector, ratchet-latch type stab in connectors, or a standard
threaded connection. In a preferred embodiment, the innerstring adapter 1910 is
removably coupled to the sealing sleeve 1915 by a standard threaded connection.
The innerstring adapter 1910 preferably includes a fluid passage 1980 that is
15 adapted to convey fluidic materials from the fluid passage 1975 into the fluid passage
1985. In a preferred embodiment, the fluid passage 1980 is adapted to convey fluidic
materials such as, for example, cement, drilling mud, epoxy, or lubricants at operating
pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute
(0 to 620.528 bar and 0 to 1 1 356.24 litres/minute).
20 The sealing sleeve 1915 is coupled to the innerstring adapter 1910 and the inner
sealing mandrel 1920. The sealing sleeve 1915 preferably comprises a substantially
hollow tubular member or members. The sealing sleeve 1915 may be fabricated from any
number of conventional commercially available materials such as, for example, oilfield
country tubular goods, carbon steel, low alloy steel, stainless steel or other high strength
25 materials. In a preferred embodiment, the sealing sleeve 1915 is fabricated from oilfield
country tubular goods in order to optimally provide mechanical properties that
substantially match the remaining components of the apparatus 1900.
The sealing sleeve 1915 may be coupled to the innerstring adapter 1 910 using any
number of conventional commercially available mechanical couplings such as, for
30 example, drillpipe connection, oilfield country tubular goods specialty type threaded
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connection, ratchet-latch type stab in connection, or a standard threaded connection. In
a preferred embodiment, the sealing sleeve 1915 is removably coupled to the innerstring
adapter 1 9 1 0 by a standard threaded connection. The sealing sleeve 1915 may be coupled
to the inner sealing mandrel 1920 using any number of conventional commercially
5 available mechanical couplings such as, for example, drillpipe connection, oilfield country
tubular goods specialty type threaded connection, or a standard threaded connection. In
a preferred embodiment, the sealing sleeve 1 9 1 5 is removably coupled to the inner sealing
mandrel 1920 by a standard threaded connection.
The sealing sleeve 1915 preferably includes a fluid passage 1985 that is adapted
10 to convey fluidic materials from the fluid passage 1 980 into the fluid passage 1 990. In a
preferred embodiment, the fluid passage 1985 is adapted to convey fluidic materials such
as, for example, cement, drill ing mud, epoxy or lubricants at operating pressures and flow
rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528 bar
and 0 to 1 1356.24 litres/minute).
15 The inner sealing mandrel 1920 is coupled to the sealing sleeve 1915 andthelower
sealing head 1930. The inner sealing mandrel 1920 preferably comprises a substantially
hollow tubular member or members. The inner sealing mandrel 1 920 may be fabricated
from any number of conventional commercially available materials such as, for example,
oilfield country tubular goods, stainless steel, low alloy steel, carbon steel or other similar
20 high strength materials. In a preferred embodiment, the inner sealing mandrel 1920 is
fabricated from stainless steel in order to optimally provide mechanical properties similar
to the other components of the apparatus 1 900 while also providing a smooth outer surface
to support seals and other moving parts that can operate with minimal wear, corrosion and
pitting. The inner sealing mandrel 1 920 may be coupled to the sealing sleeve 1915
25 using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, or a standard threaded connection . In a preferred embodiment, the inner
sealing mandrel 1920 is removably coupled to the sealing sleeve 1915 by a standard
threaded connections. The inner sealing mandrel 1920 may be coupled to the lower
30 sealing head 1 930 using any number of conventional commercially available mechanical
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couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type stab in connectors or standard
threaded connections. In a preferred embodiment, the inner sealing mandrel 1920 is
removably coupled to the lower sealing head 1930 by a standard threaded connections
5 connection.
The inner sealing mandrel 1920 preferably includes a fluid passage 1990 that is
adapted to convey fluidic materials from the fluid passage 1985 into the fluid passage
1995. In a preferred embodiment, the fluid passage 1990 is adapted to convey fluidic
materials such as, for example, cement, drilling mud, epoxy or lubricants at operating
10 pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute
(0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The upper sealing head 1925 is coupled to the outer sealing mandrel 1935 and the
expansion cone 1945. The upper sealing head 1925 is also movably coupled to the outer
surface of the inner sealing mandrel 1 920 and the inner surface of the casing 1 970. In this
15 manner, the upper sealing head 1925, outer sealing mandrel 1935, and the expansion cone
1 945 reciprocate in the axial direction. The radial clearance between the inner cylindrical
surface of the upper sealing head 1925 and the outer surface of the inner sealing mandrel
1920 may range, for example, from about 0.025 to 0.05 inches (0.0635 to 0.127
centimetres). In a preferred embodiment, the radial clearance between the inner
20 cylindrical surface of the upper sealing head 1925 and the outer surface of the inner
sealing mandrel 1920 ranges from about 0.005 to 0.01 inches (0.0127 to 0.254
centimetres) in order to optimally provide clearance for pressure seal placement. The
radial clearance between the outer cylindrical surface of the upper sealing head 1925 and
the inner surface of the casing 1970 may range, for example, from about 0.025 to 0.375
25 inches (0.0635 to 0.9525 centimetres). In a preferred embodiment, the radial clearance
between the outer cylindrical surface of the upper sealing head 1 925 and the inner surface
of the casing 1 970 ranges from about 0.025 to 0. 1 25 inches (0.0635 to 0.3 1 75 centimetres)
in order to optimally provide stabilization for the expansion cone 1945 as the expansion
cone 1945 is upwardly moved inside the casing 1970.
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The upper sealing head 1925 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The upper sealing head 1925 may be
fabricated from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, stainless steel, machine tool steel, or similar high
5 strength materials. In a preferred embodiment, the upper sealing head 1 925 is fabricated
from stainless steel in order to optimally provide high strength and smooth outer surfaces
that are resistant to wear, galling, corrosion and pitting.
The inner surface of the upper sealing head 1925 preferably includes one or more
annular sealing members 2000 for sealing the interface between the upper sealing head
10 1925 and the inner sealing mandrel 1920. The sealing members 2000 may comprise any
number of conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2000 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial motion.
15 In a preferred embodiment, the upper sealing head 1 925 includes a shoulder 2005
for supporting the upper sealing head 1925 on the lower sealing head 1930. Theifjper
sealing head 1925 may be coupled to the outer sealing mandrel 1935 using any number
of conventional commercially available mechanical couplings such as, for example,
drillpipe connection, oilfield country tubular goods specialty type threaded connection,
20 or a standard threaded connections. In a preferred embodiment, the upper sealing head
1925 is removably coupled to the outer sealing mandrel 1935 by a standard threaded
connections. In a preferred embodiment, the mechanical coupling between the upper
sealing head 1925 and the outer sealing mandrel 1935 includes one or more sealing
members 2010 for fluidicly sealing the interface between the upper sealing head 1 925 and
25 the outer sealing mandrel 1935. The sealing members 2010 may comprise any number of
conventional commercially available sealing members such as, for example, o-rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the sealing
members 2010 comprise polypak seals available from Parker Seals in order to optimally
provide sealing for a long axial stroking motion.
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The lower sealing head 1 930 is coupled to the inner sealing mandrel 1 920 and the
load mandrel 1940. The lower sealing head 1930 is also movably coupled to the inner
surface of the outer sealing mandrel 1935. In this manner, the upper sealing head 1925
and outer sealing mandrel 1935 reciprocate in the axial direction. The radial clearance
5 between the outer surface of the lower sealing head 1930 and the inner surface of the
outer sealing mandrel 1935 may range, for example, from about 0.025 to 0.05 inches
(0.0635 to 0.127 centimetres). In a preferred embodiment, the radial clearance between
the outer surface of the lower sealing head 1 930 and the inner surface of the outer sealing
mandrel 1935 ranges from about 0.005 to 0.010 inches (0.0127 to 0.0254 centimetres) (
10 in order to optimally provide a close tolerance having room for the installation of pressure
seal rings.
The lower sealing head 1930 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The lower sealing head 1930 may be
fabricated from any number of conventional commercially available materials such as, for
15 example, oilfield country tubular goods, stainless steel, machine tool steel or other similar
high strength materials. In a preferred embodiment, the lower sealing head 1930 is
fabricated from stainless steel in order to optimally provide high strength and resistance
to wear, galling, corrosion, and pitting.
The outer surface of the lower sealing head 1 930 preferably includes one or more
20 annular sealing members 2015 for sealing the interface between the lower sealing head
1 930 and the outer sealing mandrel 1935. The sealing members 20 1 5 may comprise any
number of conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a preferred
embodiment, the sealing members 2015 comprise polypak seals available from Parker
25 Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 1930 may be coupled to the inner sealing mandrel 1920
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
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preferred embodiment, the lower sealing head 1930 is removably coupled to the inner
sealing mandrel 1920 by a standard threaded connection.
In a preferred embodiment, the mechanical coupling between the lower sealing
head 1 930 and the inner sealing mandrel 1 920 includes one or more sealing members 2020
5 for fluidicly sealing the interface between the lower sealing head 1930 and the inner
sealing mandrel 1920. The sealing members 2020 may comprise any number of
conventional commercially available sealing members such as, for example, o-rings,
polypak seals, or metal spring energized seals. In a preferred embodiment, the sealing
members 2020 comprise polypak seals available from Parker Seals in order to optimally
10 provide sealing for a long axial motion.
The lower sealing head 1930 may be coupled to the load mandrel 1940 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
connections, welding, amorphous bonding or a standard threaded connection. In a
15 preferred embodiment, the lower sealing head 1930 is removably coupled to the load
mandrel 1940 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the lower sealing head 1930 and the load mandrel 1940
includes one or more sealing members 2025 for fluidicly sealing the interface between the
lower sealing head 1930 and the load mandrel 1940. The sealing members 2025 may
20 comprise any number of conventional commercially available sealing members such as,
for example, o-rings, polypak seals, or metal spring energized seals. In a preferred
embodiment, the sealing members 2025 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial stroke.
In a preferred embodiment, the lower sealing head 1930 includes a throat passage
25 2040 fluidicly coupled between the fluid passages 1990 and 1995. The throat passage
2040 is preferably of reduced size and is adapted to receive and engage with a plug 2045,
or other simitar device. In this manner, the fluid passage 1 990 is fluidicly isolated from
the fluid passage 1995. In this manner, the pressure chamber 2030 is pressurized.
The outer sealing mandrel 1 935 is coupled to the upper sealing head 1925 and the
30 expansion cone 1945. The outer sealing mandrel 1935 is also movably coupled to the
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inner surface of the casing 1 970 and the outer surface of the lower sealing head 1 930. In
this manner, the upper sealing head 1925, outer sealing mandrel 1 935, and the expansion
cone 1945 reciprocate in the axial direction. The radial clearance between the outer
surface of the outer sealing mandrel 1935 and the inner surface of the casing 1970 may
5 range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In
a preferred embodiment, the radial clearance between the outer surface of the outer sealing
mandrel 1935 and the inner surface of the casing 1970 ranges from about 0.025 to 0.125
inches (0.0635 to 0.3175 centimetres) in order to optimally provide maximum piston
surface area to maximize the radial expansion force. The radial clearance between the
10 inner surface of the outer sealing mandrel 1 935 and the outer surface of the lower sealing
head 1930 may range, for example, from about 0.025 to 0.05 inches (0.0635 to 0.127
centimetres). In a preferred embodiment, the radial clearance between the inner surface
of the outer sealing mandrel 1935 and the outer surface of the lower sealing head 1930
ranges from about 0.005 to 0.010 inches (0.0127 to 0.0254 centimetres) in order to
15 optimally provide a minimum gap for the sealing elements to bridge and seal.
The outer sealing mandrel 1935 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The outer sealing mandrel 1935 may
be fabricated from any number of conventional commercially available materials such as,
for example, low alloy steel, carbon steel, 13 chromium steel or stainless steel. In a
20 preferred embodiment, the outer sealing mandrel 1935 is fabricated from stainless steel
in order to optimally provide maximum strength and minimum wall thickness while also
providing resistance to corrosion, galling and pitting.
The outer sealing mandrel 1935 may be coupled to the upper sealing head 1925
using any number of conventional commercially available mechanical couplings such as,
25 for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, standard threaded connections, or welding. In a preferred embodiment, the
outer sealing mandrel 1935 is removably coupled to the upper sealing head 1925 by a
standard threaded connections connection. The outer sealing mandrel 1935 may be
coupled to the expansion cone 1945 using any number of conventional commercially
30 available mechanical couplings such as, for example, drillpipe connection, oilfield country
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tubular goods specialty type threaded connection, or a standard threaded connections
connection, or welding. In a preferred embodiment, the outer sealing mandrel 1935 is
removably coupled to the expansion cone 1945 by a standard threaded connections
connection.
5 The upper sealing head 1925, the lower sealing head 1930, the inner sealing
mandrel 1920, and the outer sealing mandrel 1935 together define a pressure chamber
2030. The pressure chamber 2030 is fluidicly coupled to the passage 1990 via one or
more passages 2035. During operation of the apparatus 1 900, the plug 2045 engages with
the throat passage 2040 to fluidicly isolate the fluid passage 1 990 from the fluid passage
10 1995. The pressure chamber 2030 is then pressurized which in turn causes the upper
sealing head 1925, outer sealing mandrel 1935, and expansion cone 1945 to reciprocate
in the axial direction. The axial motion of the expansion cone 1945 in turn expands the
casing 1970 in the radial direction.
The load mandrel 1940 is coupled to the lower sealing head 1930 and the
15 mechanical slip body 1955. The load mandrel 1940 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The load mandrel 1 940
may be fabricated from any number of conventional commercially available materials such
as, for example, oilfield country tubular goods, low alloy steel, carbon steel , stainless steel
or other similar high strength materials. In a preferred embodiment, the load mandrel
20 1940 is fabricated from oilfield country tubular goods in order to optimally provide high
strength.
The load mandrel 1940 may be coupled to the lower sealing head 1930 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
25 connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the load mandrel 1940 is removably coupled to the lower sealing
head 1930 by a standard threaded connection. The load mandrel 1 940 may be coupled to
the mechanical slip body 1955 using any number of conventional commercially available
mechanical couplings such as, for example, a drillpipe connection, oilfield country tubular
30 goods specialty type threaded connections, welding, amorphous bonding, or a standard
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threaded connections connection. In a preferred embodiment, the load mandrel 1940 is
removably coupled to the mechanical slip body 1955 by a standard threaded connections
connection.
The load mandrel 1 940 preferably includes a fluid passage 1 995 that is adapted to
5 convey fluidic materials from the fluid passage 1 990 to the region outside of the apparatus
1900. In a preferred embodiment, the fluid passage 1995 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
10 The expansion cone 1945 is coupled to the outer sealing mandrel 1935. The
expansion cone 1945 is also movably coupled to the inner surface of the casing 1 970. In
this manner, the upper sealing head 1925, outer sealing mandrel 1 935, and the expansion
cone 1945 reciprocate in the axial direction. The reciprocation of the expansion cone
1945 causes the casing 1970 to expand in the radial direction.
15 The expansion cone 1945 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius of the outside
conical surface may range, for example, from about 2 to 34 inches (5.08 to 86.36
centimetres). In a preferred embodiment, the outside radius of the outside conical surface
ranges from about 3 to 28 inches (7.62 to 7 1 . 1 2 centimetres) in order to optimally provide
20 cone dimensions for the typical range of tubular members.
The axial length of the expansion cone 1945 may range, for example, from about
2 to 8 times the largest outer diameter of the expansion cone 1945. In a preferred
embodiment, the axial length of the expansion cone 1945 ranges from about 3 to 5 times
the largest outer diameter of the expansion cone 1945 in order to optimally provide
25 stability and centralization of the expansion cone 1945 during the expansion process. In
a preferred embodiment, the angle of attack of the expansion cone 1 945 ranges from about
5 to 30 degrees in order to optimally balance friction forces with the desired amount of
radial expansion. The expansion cone 1945 angle of attack will vary as a function of the
operating parameters of the particular expansion operation.
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The expansion cone 1945 may be fabricated from any number of conventional
commercially available materials such as, for example, machine tool steel, ceramics,
tungsten carbide, nitride steel, or other similar high strength materials. In a preferred
embodiment, the expansion cone 1945 is fabricated from D2 machine tool steel in order
5 to optimally provide high strength and resistance to corrosion, wear, galling, and pitting.
In a particularly preferred embodiment, the outside surface of the expansion cone 1945 has
a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength and resist wear and galling.
The expansion cone 1945 may be coupled to the outside sealing mandrel 1935
10 using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield tubular country goods specialty type threaded
connection, welding, amorphous bonding, or a standard threaded connections connection.
In a preferred embodiment, the expansion cone 1945 is coupled to the outside sealing
mandrel 1935 using a standard threaded connections connection in order to optimally
15 provide connector strength for the typical operating loading conditions while also
permitting easy replacement of the expansion cone 1945.
The mandrel launcher 1950 is coupled to the casing 1970. The mandrel launcher
1950 comprises a tubular section of casing having a reduced wall thickness compared to
the casing 1970. In a preferred embodiment, the wall thickness of the mandrel launcher
20 is about 50 to 100 % of the wall thickness of the casing 1970. In this manner, the
initiation of the radial expansion of the casing 1970 is facilitated, and the insertion of the
larger outside diameter mandrel launcher 1950 into the wellbore and/or casing is
facilitated.
The mandrel launcher 1 950 may be coupled to the casing 1 970 using any number
25 of conventional mechanical couplings. The mandrel launcher 1950 may have a wall
thickness ranging, for example, from about 0. 1 5 to 1 .5 inches (0.38 1 to 3.8 1 centimetres).
In a preferred embodiment, the wall thickness of the mandrel launcher 1950 ranges from
about 0.25 to 0.75 inches (0.635 to 1 .905 centimetres) in order to optimally provide high
strength with a small overall profile. The mandrel launcher 1950 may be fabricated from
30 any number of conventional commercially available materials such as, for example, oil
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field tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the mandrel launcher 1950 is fabricated
from oil field tubular goods of higher strength but lower wall thickness than the casing
1970 in order to optimally provide a thin walled container with approximately the same
5 burst strength as the casing 1970.
The mechanical slip body 1955 is coupled to the load mandrel 1970, the
mechanical slips 1960, and the drag blocks 1965. The mechanical slip body 1955
preferably comprises a tubular member having an inner passage 2050 fluidicly coupled
to the passage 1 995. In this manner, fluidic materials may be conveyed from the passage
10 2050 to a region outside of the apparatus 1900.
The mechanical slip body 1955 may be coupled to the load mandrel 1 940 using any
number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 1955 is removably coupled to the load mandrel 1940 using a
standard threaded connection in order to optimally provide high strength and permit the
15 mechanical slip body 1955 to be easily replaced. The mechanical slip body 1 955 may be
coupled to the mechanical slips 1955 using any number of conventional mechanical
couplings. In a preferred embodiment, the mechanical slip body 1955 is removably
coupled to the mechanical slips 1 955 using threads and sliding steel retainer rings in order
to optimally provide high strength coupling and also permit easy replacement of the
20 mechanical slips 1 955 . The mechanical slip body 1 955 may be coupled to the drag blocks
1965 using any number of conventional mechanical couplings. In a preferred
embodiment, the mechanical slip body 1 955 is removably coupled to the drag blocks 1 965
using threaded connections and sliding steel retainer rings in order to optimally provide
high strength and also permit easy replacement of the drag blocks 1965.
25 The mechanical slips 1960 are coupled to the outside surface of the mechanical slip
body 1955. During operation of the apparatus 1900, the mechanical slips 1960 prevent
upward movement of the casing 1970 and mandrel launcher 1950. In this manner, during
the axial reciprocation of the expansion cone 1945, the casing 1970 and mandrel launcher
1950 are maintained in a substantially stationary position. In this manner, the mandrel
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launcher 1 950 and casing 1 970 are expanded in the radial direction by the axial movement
of the expansion cone 1945.
The mechanical slips 1960 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer tungsten
5 carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L
retrievable bridge plug tungsten carbide upper mechanical slips. In a preferred
embodiment, the mechanical slips 1960 comprise RTTS packer tungsten carbide
mechanical slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 1970 during the expansion process.
10 The drag blocks 1965 are coupled to the outside surface of the mechanical slip
body 1955. During operation of the apparatus 1900, the drag blocks 1965 prevent upward
movement of the casing 1 970 and mandrel launcher 1 950. In this manner, during the axial
reciprocation of the expansion cone 1945, the casing 1970 and mandrel launcher 1950 are
maintained in a substantially stationary position. In this manner, the mandrel launcher
15 1950 and casing 1970 are expanded in the radial direction by the axial movement of the
expansion cone 1945.
The drag blocks 1965 may comprise any number of conventional commercially
available mechanical slips such as, for example, RTTS packer tungsten carbide
mechanical slips, RTTS packer wicker type mechanical slips or Model 3L retrievable
20 bridge plug tungsten carbide upper mechanical slips. In a preferred embodiment, the drag
blocks 1965 comprise RTTS packer tungsten carbide mechanical slips available from
Halliburton Energy Services in order to optimally provide resistance to axial movement
of the casing 1970 during the expansion process.
The casing 1970 is coupled to the mandrel launcher 1950. The casing 1970 is
25 farther removably coupled to the me^^ Thecasing
1970 preferably comprises a tubular member. The casing 1970 may be fabricated from
any number of conventional commercially available materials such as, for example, slotted
tubulars, oil field country tubular goods, low alloy steel, carbon steel, stainless steel or
other similar high strength materials. In a preferred embodiment, the casing 1970 is
30 fabricated from oilfield country tubular goods available from various foreign and domestic
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steel mills in order to optimally provide high strength. In a preferred embodiment, the
upper end of the casing 1 970 includes one or more sealing members positioned about the
exterior of the casing 1970.
During operation, the apparatus 1 900 is positioned in a wellbore with the upper end
5 of the casing 1970 positioned in an overlapping relationship within an existing wellbore
casing. In order minimize surge pressures within the borehole during placement of the
apparatus 1 900, the fluid passage 1 975 is preferably provided with one or more pressure
relief passages. During the placement of the apparatus 1 900 in the wellbore, the casing
1970 is supported by the expansion cone 1945.
10 After positioning of the apparatus 1900 within the bore hole in an overlapping
relationship with an existing section of wellbore casing, a first fluidic material is pumped
into the fluid passage 1 975 from a surface location. The first fluidic material is conveyed
from the fluid passage 1975 to the fluid passages 1980, 1985, 1990, 1995,and2050. The
first fluidic material will then exit the apparatus and fill the annular region between the
15 outside of the apparatus 1900 and the interior walls of the bore hole.
The first fluidic material may comprise any number of conventional commercially
available materials such as, for example, drilling mud, water, epoxy or cement. In a
preferred embodiment, the first fluidic material comprises a hardenable fluidic sealing
material such as, for example, cement or epoxy. In this manner, a wellbore casing having
20 an outer annular layer of a hardenable material may be formed.
The first fluidic material may be pumped into the apparatus 1900 at operating
pressures and flow rates ranging, for example, from about 0 to 4,500 psi, and 0 to 3,000
gallons/minute (0 to 310.264 bar, and 0 to 11356.24 litres/minute). In a preferred
embodiment, the first fluidic material is pumped into the apparatus 1900 at operating
25 pressures and flow rates ranging from about 0 to 4,500 psi and 0 to 3 ,000 gallons/minute
(0 to 3 10.264 bar and 0 to 1 1 356.24 litres/minute) in order to optimally provide operating
pressures and flow rates for typical operating conditions.
At a predetermined point in the injection of the first fluidic material such as, for
example, after the annular region outside of the apparatus 1900 has been filled to a
30 predetermined level, a plug 2045, dart, or other similar device is introduced into the first
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fluidic material. The plug 2045 lodges in the throat passage 2040 thereby fluidicly
isolating the fluid passage 1990 from the fluid passage 1995.
After placement of the plug 2045 in the throat passage 2040, a second fluidic
material is pumped into the fluid passage 1 975 in order to pressurize the pressure chamber
5 2030. The second fluidic material may comprise any number of conventional
commercially available materials such as, for example, water, drilling gases, drilling mud
or lubricant In a preferred embodiment, the second fluidic material comprises a non-
hardenable fluidic material such as, for example, water, drilling mud or lubricant in order
minimize frictional forces.
10 The second fluidic material may be pumped into the apparatus 1 900 at operating
pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500
gallons/minute (0 to 310.264 bar and 0 to 11356.24 litres/minute). In a preferred
embodiment, the second fluidic material is pumped into the apparatus 1900 at operating
pressures and flow rates ranging from about 0 to 3,500 psi, and 0 to 1 ,200 gallons/minute
15 (0 to 24 1 .3 1 6 bar and 0 to 4542.49 litres/minute) in order to optimally provide expansion
of the casing 1970.
The pressurization of the pressure chamber 2030 causes the upper sealing head
1925, outer sealing mandrel 1935, and expansion cone 1 945 to move in an axial direction.
As the expansion cone 1945 moves in the axial direction, the expansion cone 1945 pulls
20 the mandrel launcher 1950 and drag blocks 1965 along, which sets the mechanical slips
1960 and stops further axial movement of the mandrel launcher 1950 and casing 1970.
In this manner, the axial movement of the expansion cone 1945 radially expands the
mandrel launcher 1950 and casing 1970.
Once the upper sealing head 1925, outer sealing mandrel 1935, and expansion cone
25 1945 complete an axial stroke, the operating pressure of the second fluidic material is
reduced and the drill string 1905 is raised. This causes the inner sealing mandrel 1920,
lower sealing head 1930, load mandrel 1940, and mechanical slip body 1955 to move
upward. This unsets the mechanical slips 1 960 and permits the mechanical slips 1960 and
drag blocks 1965 to be moved upward within the mandrel launcher and casing 1970.
30 When the lower sealing head 1930 contacts the upper sealing head 1925, the second
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fluidic material is again pressurized and the radial expansion process continues. In this
manner, the mandrel launcher 1950 and casing 1 970 are radial expanded through repeated
axial strokes of the upper sealing head 1925, outer sealing mandrel 1935 and expansion
cone 1945. Throughput the radial expansion process, the upper end of the casing 1970 is
5 preferably maintained in an overlapping relation with an existing section of wellbore
casing.
At the end of the radial expansion process, the upper end of the casing 1970 is
expanded into intimate contact with the inside surface of the lower end of the existing
wellbore casing. In a preferred embodiment, the sealing members provided at the upper
10 end of the casing 1 970 provide a fluidic seal between the outside surface of the upper end
of the casing 1970 and the inside surface of the lower end of the existing wellbore casing.
In a preferred embodiment, the contact pressure between the casing 1 970 and the existing
section of wellbore casing ranges from about 400 to 10,000 psi (27.58 to 689.476 bar) in
order to optimally provide contact pressure for activating sealing members, provide
15 optimal resistance to axial movement of the expanded casing 1 970, and optimally support
typical tensile and compressive loads.
In a preferred embodiment, as the expansion cone 1945 nears the end of the casing
1 970, the operating flow rate of the second fluidic material is reduced in order to minimize
shock to the apparatus 1900. In an alternative embodiment, the apparatus 1900 includes
20 a shock absorber for absorbing the shock created by the completion of the radial expansion
of the casing 1970.
In a preferred embodiment, the reduced operating pressure of the second fluidic
material ranges from about 100 to 1 ,000 psi (6.8947 to 68.947 bar) as the expansion cone
1945 nears the end of the casing 1970 in order to optimally provide reduced axial
25 movement and velocity of the expansion cone 1945. In a preferred embodiment, the
operating pressure of the second fluidic material is reduced during the return stroke of the
apparatus 1900 to the range of about 0 to 500 psi (0 to 34.47 bar) in order minimize the
resistance to the movement of the expansion cone 1945. In a preferred embodiment, the
stroke length of the apparatus 1900 ranges from about 10 to 45 feet (3.048 to 13.716
30 metres) in order to optimally provide equipment lengths that can be handled by typical oil
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well rigging equipment while also minimizing the frequency at which the expansion cone
1945 must be stopped so the apparatus 1900 can be re-stroked for further expansion
operations.
In an alternative embodiment, at least a portion of the upper sealing head 1925
5 includes an expansion cone for radially expanding the mandrel launcher 1 950 and casing
1970 during operation of the apparatus 1900 in order to increase the surface area of the
casing 1 970 acted upon during the radial expansion process. In this manner, the operating
pressures can be reduced.
In an alternative embodiment, mechanical slips are positioned in an axial location
10 between the sealing sleeve 1 91 5 and the inner sealing mandrel 1 920 in order to simplify
the operation and assembly of the apparatus 1900.
Upon the complete radial expansion of the casing 1970, if applicable, the first
fluidic material is permitted to cure within the annular region between the outside of the
expanded casing 1970 and the interior walls of the wellbore. In the case where the
15 expanded casing 1970 is slotted, the cured fluidic material will preferably permeate and
envelop the expanded casing. In this manner, a new section of wellbore casing is formed
within a wellbore. Alternatively, the apparatus 1900 may be used to join a first section of
pipeline to an existing section of pipeline. Alternatively, the apparatus 1 900 may be used
to directly line the interior of a wellbore with a casing, without the use of an outer annular
20 layer of ahardenable material. Alternatively, the apparatus 1900 may be used to expand
a tubular support member in a hole.
During the radial expansion process, the pressurized areas of the apparatus 1900
are limited to the fluid passages 1975, 1980, 1985, and 1990, and the pressure chamber
2030. No fluid pressure acts directly on the mandrel launcher 1 950 and casing 1 970. This
25 permits the use of operating pressures higher than the mandrel launcher 1950 and casing
1970 could normally withstand.
Referring now to Figure 16, a preferred embodiment of an apparatus 2100 for
forming a mono-diameter wellbore casing will be described. The apparatus 2100
preferably includes a drillpipe 2105, an innerstring adapter 21 10, a sealing sleeve 2115,
30 an inner sealing mandrel 2120, slips 2125, upper sealing head 2130, lower sealing head
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2135, outer sealing mandrel 2140, load mandrel 2145, expansion cone 2150, and casing
2155.
The drillpipe 2105 is coupled to the innerstring adapter 2110. During operation
of the apparatus 2100, the drillpipe 2105 supports the apparatus 2100. The drillpipe 2105
5 preferably comprises a substantially hollow tubular member or members. The drillpipe
2105 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength material. In a preferred embodiment, the
drillpipe 2105 is fabricated from coiled tubing in order to faciliate the placement of the
10 apparatus 1900 in non-vertical wellbores. The drillpipe 2105 may be coupled to the
innerstring adapter 2110 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, ratchet-latch type connection, or a standard
threaded connection. In a preferred embodiment, the drillpipe 2 1 05 is removably coupled
15 to the innerstring adapter 21 10 by a drill pipe connection.
The drillpipe 2105 preferably includes a fluid passage 2160 that is adapted to
convey fluidic materials from a surface location into the fluid passage 2165. In a preferred
embodiment, the fluid passage 2160 is adapted to convey fluidic materials such as, for
example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow
20 rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528 bar
and 0 to 1 1356.24 litres/minute).
The innerstring adapter 21 10 is coupled to the drill string 2105 and the sealing
sleeve 2115. The innerstring adapter 2110 preferably comprises a substantially hollow
tubular member or members. The innerstring adapter 2110 may be fabricated from any
25 number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the innerstring adapter 2 1 1 0 is fabricated
from stainless steel in order to optimally provide high strength, low friction, and resistance
to corrosion and wear.
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The innerstring adapter 2110 may be coupled to the drill string 2105 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, ratchet-latch type connection or a standard threaded connection. In a
5 preferred embodiment, the innerstring adapter 2 1 1 0 is removably coupled to the drill pipe
2105 by a drillpipe connection. The innerstring adapter 2110 may be coupled to the
sealing sleeve 2115 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type threaded connection, or a standard
10 threaded connection. In a preferred embodiment, the innerstring adapter 2110 is
removably coupled to the sealing sleeve 21 15 by a standard threaded connection.
The innerstring adapter 2110 preferably includes a fluid passage 2165 that is
adapted to convey fluidic materials from the fluid passage 2160 into the fluid passage
2170. In a preferred embodiment, the fluid passage 2165 is adapted to convey fluidic
15 materials such as, for example, cement, epoxy, water drilling muds, or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The sealing sleeve 21 15 is coupled to the innerstring adapter 2110 and the inner
sealing mandrel 2120. The sealing sleeve 2115 preferably comprises a substantially
20 hollow tubular member or members. The sealing sleeve 2 115 may be fabricated from any
number of conventional commercially available materials such as, for example, oil field
tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength
materials. In a preferred embodiment, the sealing sleeve 21 1 5 is fabricated from stainless
steel in order to optimally provide high strength, low friction surfaces, and resistance to
25 corrosion, wear, galling, and pitting.
The sealing sleeve 2115 may be coupled to the innerstring adapter 2110 using any
number of conventional commercially available mechanical couplings such as, for
example, a standard threaded connection, oilfield country tubular goods specialty type
threaded connections, welding, amorphous bonding, or a standard threaded connection.
30 In a preferred embodiment, the sealing sleeve 2115 is removably coupled to the
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innerstring adapter 2 1 1 0 by a standard threaded connection. The sealing sleeve 2115 may
be coupled to the inner sealing mandrel 2120 using any number of conventional
commercially available mechanical couplings such as, for example, a standard threaded
connection, oilfield country tubular goods specialty type threaded connections, welding,
5 amorphous bonding, or a standard threaded connection. In a preferred embodiment, the
sealing sleeve 2 1 1 5 is removably coupled to the inner sealing mandrel 2 1 20 by a standard
threaded connection.
The sealing sleeve 2115 preferably includes a fluid passage 2 1 70 that is adapted
to convey fluidic materials from the fluid passage 2165 into the fluid passage 2175. In a
10 preferred embodiment, the fluid passage 2 1 70 is adapted to convey fluidic materials such
as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures
and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356,24 litres/minute).
The inner sealing mandrel 2120 is coupled to the sealing sleeve 2115, slips 2125,
15 and the lower sealing head 2135. The inner sealing mandrel 2120 preferably comprises
a substantially hollow tubular member or members. The inner sealing mandrel 2 1 20 may
be fabricated from any number of conventional commercially available materials such as,
for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the inner sealing
20 mandrel 2 1 20 is fabricated from stainless steel in order to optimally provide high strength,
low friction surfaces, and corrosion and wear resistance.
The inner sealing mandrel 2120 may be coupled to the sealing sleeve 21 15 using
any number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
25 connection, or a standard threaded connection. In a preferred embodiment, the inner
sealing mandrel 2120 is removably coupled to the sealing sleeve 2115 by a standard
threaded connection. The standard threaded connection provides high strength and
permits easy replacement of components . The inner sealing mandrel 2 1 20 may be coupled
to the slips 2125 using any number of conventional commercially available mechanical
30 couplings such as, for example, welding, amorphous bonding, or a standard threaded
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connection. In a preferred embodiment, the inner sealing mandrel 2120 is removably
coupled to the slips 2125 by a standard threaded connection. The inner sealing mandrel
2120 may be coupled to the lower sealing head 2135 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe connection,
5 oilfield country tubular goods specialty type threaded connection, welding, amorphous
bonding or a standard threaded connection. In a preferred embodiment, the inner sealing
mandrel 2 120 is removably coupled to the lower sealing head 2 1 35 by a standard threaded
connection.
The inner sealing mandrel 2120 preferably includes a fluid passage 2175 that is
10 adapted to convey fluidic materials from the fluid passage 2170 into the fluid passage
2180. In a preferred embodiment, the fluid passage 2175 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
15 The slips 2125 are coupled to the outer surface of the inner sealing mandrel 2120.
During operation of the apparatus 2100, the slips 2125 preferably maintain the casing
2 1 55 in a substantially stationary position during the radial expansion of the casing 2155.
In a preferred embodiment, the slips 2125 are activated using the fluid passages 2185 to
convey pressurized fluid material into the slips 2125.
2 0 The slips 2 1 25 may comprise any number of commercially available hydraulic slips
such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L
retrievable bridge plug hydraulic slips. In a preferred embodiment, the slips 2125
comprise RTTS packer tungsten carbide hydraulic slips available from Halliburton Energy
Services in order to optimally provide resistance to axial movement of the casing 2155
25 during the expansion process. In a particularly preferred embodiment, the slips include
a fluid passage 2 1 90, pressure chamber 2 1 95, spring return 2200, and slip member 2205.
The slips 2125 may be coupled to the inner sealing mandrel 2120 using any
number of conventional mechanical couplings. In a preferred embodiment, the slips 2 1 25
are removably coupled to the outer surface of the inner sealing mandrel 2 1 20 by a thread
30 connection in order to optimally provide interchangeability of parts.
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The upper sealing head 2130 is coupled to the outer sealing mandrel 2140 and
expansion cone 2150. The upper sealing head 2 1 30 is also movably coupled to the outer
surface of the inner sealing mandrel 2 120 and the inner surface of the casing 2 1 55. In this
manner, the upper sealing head 2130 reciprocates in the axial direction. The radial
5 clearance between the inner cylindrical surface of the upper sealing head 2130 and the
outer surface of the inner sealing mandrel 2 1 20 may range, for example, from about 0.025
to 0.05 inches (0.0635 to 0.127 centimetres). In a preferred embodiment, the radial
clearance between the inner cylindrical surface of the upper sealing head 2130 and the
outer surface of the inner sealing mandrel 2120 ranges from about 0.005 to 0.010 inches
10 (0.0127 to 0.0254 centimetres) in order to optimally provide a pressure seal. The radial
clearance between the outer cylindrical surface of the upper sealing head 2130 and the
inner surface of the casing 2 1 55 may range, for example, from about 0.025 to 0.375 inches
(0.0635 to 0.9525 centimetres). In a preferred embodiment, the radial clearance between
the outer cylindrical surface of the upper sealing head 2130 and the inner surface of the
15 casing 2155 ranges from about 0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in
order to optimally provide stabilization for the expansion cone 2130 during axial
movement of the expansion cone 2130.
The upper sealing head 2130 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The upper sealing head 2130 may be
20 fabricated from any number of conventional commercially available materials such as, for
example, low alloy steel, carbon steel, stainless steel or other similar high strength
materials. In a preferred embodiment, the upper sealing head 2130 is fabricated from
stainless steel in order to optimally provide high strength, corrosion resistance, and low
friction surfaces. The inner surface of the upper sealing head 2 1 30 preferably includes one
25 or more annular sealing members 22 1 0 for sealing the interface between the upper sealing
head 2130 and the inner sealing mandrel 2120. The sealing members 22 10 may comprise
any number of conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a preferred
embodiment, the sealing members 2210 comprise polypak seals available from Parker
30 Seals in order to optimally provide sealing for a long axial stroke.
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In a preferred embodiment, the upper sealing head 2130 includes a shoulder 221 5
for supporting the upper sealing head 2130 on the lower sealing head 2135.
The upper sealing head 2130 may be coupled to the outer sealing mandrel 2140
using any number of conventional commercially available mechanical couplings such as,
5 for example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the upper sealing head 2130 is removably coupled to the outer
sealing mandrel 2 1 40 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the upper sealing head 2130 and the outer sealing mandrel
10 2140 includes one or more sealing members 2220 for fluidicly sealing the interface
between the upper sealing head 2130 and the outer sealing mandrel 2140. The sealing
members 2220 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals, or metal spring energized seals. In
apreferred embodiment, the sealing members 2220 comprise polypak seals available from
15 Parker Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 2135 is coupled to the inner sealing mandrel 2120 and the
load mandrel 2145. The lower sealing head 2135 is also movably coupled to the inner
surface of the outer sealing mandrel 2 140. In this manner, the upper sealing head 2130,
outer sealing mandrel 2140, and expansion cone 2 150 reciprocate in the axial direction.
20 The radial clearance between the outer surface of the lower sealing head 2135 and the
inner surface of the outer sealing mandrel 2140 may range, for example, from about
0.0025 to 0.05 inches (0.00635 to 0.127 centimetres). In a preferred embodiment, the
radial clearance between the outer surface of the lower sealing head 2135 and the inner
surface of the outer sealing mandrel 2140 ranges from about 0.0025 to 0.05 inches
25 (0.00635 to 0.127 centimetres) in order to optimally provide minimal radial clearance.
The lower sealing head 2135 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The lower sealing head 2135 may be
fabricated from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or
30 other similar high strength materials. In a preferred embodiment, the lower sealing head
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2135 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the lower sealing
head 2135 preferably includes one or more annular sealing members 2225 for sealing the
interface between the lower sealing head 2135 and the outer sealing mandrel 2140. The
5 sealing members 2225 may comprise any number of conventional commercially available
annular sealing members such as, for example, o-rings, polypak seals or metal spring
energized seals. In a preferred embodiment, the sealing members 2225 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a long axial
stroke.
10 The lower sealing head 2 1 35 may be coupled to the inner sealing mandrel 2 1 20
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the lower sealing head 2135 is removably coupled to the inner
1 5 sealing mandrel 2 1 20 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the lower sealing head 2135 and the inner sealing mandrel
2120 includes one or more sealing members 2230 for fluidicly sealing the interface
between the lower sealing head 2135 and the inner sealing mandrel 2120. The sealing
members 2230 may comprise any number of conventional commercially available sealing
20 members such as, for example, o-rings, polypak seals, or metal spring energized seals. In
a preferred embodiment, the sealing members 2230 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 2135 may be coupled to the load mandrel 2145 using any
number of conventional commercially available mechanical couplings such as, for
25 example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the lower sealing head 2135 is removably coupled to the load
mandrel 2145 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the lower sealing head 2135 and the load mandrel 2145
30 includes one or more sealing members 2235 for fluidicly sealing the interface between the
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lower sealing head 1930 and the load mandrel 2145. The sealing members 2235 may
comprise any number of conventional commercially available sealing members such as,
for example, o-rings, polypak seals, or metal spring energized seals. In a preferred
embodiment, the sealing members 2235 comprise polypak seals available from Parker
5 Seals in order to optimally provide sealing for a long axial stroke.
In a preferred embodiment, the lower sealing head 2135 includes a throat passage
2240 fluidicly coupled between the fluid passages 2175 and 2180. The throat passage
2240 is preferably of reduced size and is adapted to receive and engage with a plug 2245,
or other similar device. In this manner, the fluid passage 2175 is fluidicly isolated from
10 the fluid passage 2180. In this manner, the pressure chamber 2250 is pressurized.
The outer sealing mandrel 2 1 40 is coupled to the upper sealing head 2130 and the
expansion cone 2150. The outer sealing mandrel 2140 is also movably coupled to the
inner surface of the casing 2155 and the outer surface of the lower sealing head 2135. In
this manner, the upper sealing head 2130, outer sealing mandrel 2 140, and the expansion
15 cone 2150 reciprocate in the axial direction. The radial clearance between the outer
surface of the outer sealing mandrel 2140 and the inner surface of the casing 2155 may
range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In
a preferred embodiment, the radial clearance between the outer surface of the outer sealing
mandrel 2 1 40 and the inner surface of the casing 2 1 55 ranges from about 0.025 to 0. 1 25
20 inches (0.0635 to 0.3 175 centimetres) in order to optimally provide stabilization for the
expansion cone 2130 during the expansion process. The radial clearance between the
inner surface of the outer sealing mandrel 21 40 and the outer surface of the lower sealing
head 2135 may range, for example, from about 0.005 to 0.125 inches (0.0127 to 0.3175
centimetres). In a preferred embodiment, the radial clearance between the inner surface
25 of the outer sealing mandrel 2140 and the outer surface of the lower sealing head 2135
ranges from about 0.005 to 0.010 inches (0.0127 to 0.0254 centimetres) in order to
optimally provide minimal radial clearance.
The outer sealing mandrel 2140 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The outer sealing mandrel 2140 may
30 be fabricated from any number of conventional commercially available materials such as,
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for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel,
or other similar high strength materials. In a preferred embodiment, the outer sealing
mandrel 2 1 40 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
5 The outer sealing mandrel 2140 may be coupled to the upper sealing head 2130
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the outer sealing mandrel 2140 is removably coupled to the upper
10 sealing head 2130 by a standard threaded connection. The outer sealing mandrel 2 140
may be coupled to the expansion cone 2150 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, welding, amorphous
bonding, or a standard threaded connection. In a preferred embodiment, the outer sealing
15 mandrel 2140 is removably coupled to the expansion cone 2150 by a standard threaded
connection.
The upper sealing head 2 130, the lower sealing head 2135, inner sealing mandrel
2120, and the outer sealing mandrel 2140 together define a pressure chamber 2250. The
pressure chamber 2250 is fluidicly coupled to the passage 2 1 75 via one or more passages
20 2255. During operation of the apparatus 2100, the plug 2245 engages with the throat
passage 2240 to fluidicly isolate the fluid passage 2175 from the fluid passage 2 1 80. The
pressure chamber 2250 is then pressurized which in turn causes the upper sealing head
2130, outer sealing mandrel 2140, and expansion cone 2150 to reciprocate in the axial
direction. The axial motion of the expansion cone 2150 in turn expands the casing 2155
25 in the radial direction.
The load mandrel 2145 is coupled to the lower sealing head 2135. The load
mandrel 2145 preferably comprises an annular member having substantially cylindrical
inner and outer surfaces. The load mandrel 2145 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield country
30 tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength
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materials. In a preferred embodiment, the load mandrel 2 1 45 is fabricated from stainless
steel in order to optimally provide high strength, corrosion resistance, and low friction
bearing surfaces.
The load mandrel 2145 may be coupled to the lower sealing head 2135 using any
5 number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the load mandrel 2145 is removably coupled to the lower sealing
head 2 135 by a standard threaded connection in order to optimally provide high strength
10 and permit easy replacement of the load mandrel 2145.
The load mandrel 2 1 45 preferably includes a fluid passage 2 1 80 that is adapted to
convey fluidic materials from the fluid passage 2 1 80 to the region outside of the apparatus
2100. In a preferred embodiment, the fluid passage 2180 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at
15 operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The expansion cone 2150 is coupled to the outer sealing mandrel 2140. The
expansion cone 2 1 50 is also movably coupled to the inner surface of the casing 2155. In
this manner, the upper sealing head 2130, outer sealing mandrel 2140, and the expansion
20 cone 2150 reciprocate in the axial direction. The reciprocation of the expansion cone
2150 causes the casing 2155 to expand in the radial direction.
The expansion cone 2150 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius of the outside
conical surface may range, for example, from about 2 to 34 inches (5.08 to 86.36
25 centimetres). In a preferred embodiment, the outside radius of the outside conical surface
ranges from about 3 to 28 inches (7.62 to 7 1 . 1 2 centimetres) in order to optimally provide
cone dimensions that are optimal for typical casings. The axial length of the expansion
cone 21 50 may range, for example, from about 2 to 6 times the largest outside diameter
of the expansion cone 21 50. In a preferred embodiment, the axial length of the expansion
30 cone 2150 ranges from about 3 to 5 times the largest outside diameter of the expansion
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cone 2 1 50 in order to optimally provide stability and centralization of the expansion cone
2150 during the expansion process. In a particularly preferred embodiment, the maximum
outside diameter of the expansion cone 2150 is between about 90 to 100 % of the inside
diameter of the existing wellbore that the casing 2155 will be joined with. In a preferred
5 embodiment, the angle of attack of the expansion cone 2150 ranges from about 5 to 30
degrees in order to optimally balance friction forces and radial expansion forces. The
optimal expansion cone 2150 angle of attack will vary as a function of the particular
operating conditions of the expansion operation.
The expansion cone 2150 may be fabricated from any number of conventional
10 commercially available materials such as, for example, machine tool steel, nitride steel,
titanium, tungsten carbide, ceramics, or other similar high strength materials. In a
preferred embodiment, the expansion cone 21 50 is fabricated from D2 machine tool steel
in order to optimally provide high strength and resistance to wear and galling. In a
particularly preferred embodiment, the outside surface of the expansion cone 2150 has a
15 surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
resistance to wear.
The expansion cone 2150 may be coupled to the outside sealing mandrel 2140
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
20 connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the expansion cone 2 1 50 is coupled to the outside sealing mandrel
2 1 40 using a standard threaded connection in order to optimally provide high strength and
permit the expansion cone 2150 to be easily replaced.
The casing 2 1 55 is removably coupled to the slips 2 1 25 and expansion cone 2 1 50.
25 The casing 2155 preferably comprises a tubular member. The casing 2155 may be
fabricated from any number of conventional commercially available materials such as, for
example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength material. In a preferred embodiment, the
casing 2155 is fabricated from oilfield country tubular goods available from various
30 foreign and domestic steel mills in order to optimally provide high strength.
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In a preferred embodiment, the upper end 2260 of the casing 2155 includes a thin
wall section 2265 and an outer annular sealing member 2270. In a preferred embodiment,
the wall thickness of the thin wall section 2265 is about 50 to 100 % of the regular wall
thickness of the casing 2155. In this manner, the upper end 2260 of the casing 2 1 55 may
5 be easily expanded and deformed into intimate contact with the lower end of an existing
section of wellbore casing. In a preferred embodiment, the lower end of the existing
section of casing also includes a thin wall section. In this manner, the radial expansion of
the thin walled section 2265 of casing 2155 into the thin walled section of the existing
wellbore casing results in a wellbore casing having a substantially constant inside
10 diameter.
The annular sealing member 2270 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, epoxy,
rubber, metal or plastic. In a preferred embodiment, the annular sealing member 2270 is
fabricated from StrataLock epoxy in order to optimally provide compressibility and
15 resistance to wear. The outside diameter of the annular sealing member 2270 preferably
ranges from about 70 to 95 % of the inside diameter of the lower section of the wellbore
casing that the casing 2155 is joined to. In this manner, after expansion, the annular
sealing member 2270 preferably provides a fluidic seal and also preferably provides
sufficient frictional force with the inside surface of the existing section of wellbore casing
20 during the radial expansion of the casing 21 55 to support the casing 2155.
In a preferred embodiment, the lower end 2275 of the casing 2155 includes a thin
wall section 2280 and an outer annular sealing member 2285. In a preferred embodiment,
the wall thickness of the thin wall section 2280 is about 50 to 100 % of the regular wall
thickness of the casing 2155. In this manner, the lower end 2275 of the casing 2 1 55 may
25 be easily expanded and deformed. Furthermore, in this manner, an other section of casing
may be easily joined with the lower end 2275 of the casing 2155 using a radial expansion
process. In a preferred embodiment, the upper end of the other section of casing also
includes a thin wall section. In this manner, the radial expansion of the thin walled section
of the upper end of the other casing into the thin walled section 2280 of the lower end of
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the casing 2155 results in a wellbore casing having a substantially constant inside
diameter.
The annular sealing member 2285 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, epoxy,
5 rubber, metal or plastic. In a preferred embodiment, the annular sealing member 2285 is
fabricated from StrataLock epoxy in order to optimally provide compressibility and wear
resistance. The outside diameter of the annular sealing member 2285 preferably ranges
from about 70 to 95 % of the inside diameter of the lower section of the existing wellbore
casing that the casing 2 1 55 is joined to. In this manner, the annular sealing member 2285
10 preferably provides a fluidic seal and also preferably provides sufficient frictional force
with the inside wall of the wellbore during the radial expansion of the casing 2155 to
support the casing 2 1 55.
During operation, the apparatus 2 1 00 is preferably positioned in a wellbore with
the upper end 2260 of the casing 2155 positioned in an overlapping relationship with the
15 lower end of an existing wellbore casing. In a particularly preferred embodiment, the thin
wall section 2265 of the casing 2155 is positioned in opposing overlapping relation with
the thin wall section and outer annular sealing member of the lower end of the existing
section of wellbore casing. In this manner, the radial expansion of the casing 2155 will
compress the thin wall sections and annular compressible members of the upper end 2260
20 of the casing 21 55 and the lower end of the existing wellbore casing into intimate contact.
During the positioning of the apparatus 2 100 in the wellbore, the casing 2 1 55 is supported
by the expansion cone 2150.
After positioning of the apparatus 2 100, a first fluidic material is then pumped into
the fluid passage 2160. The first fluidic material may comprise any number of
25 conventional commercially available materials such as, for example, drilling mud, water,
epoxy, or cement. In a preferred embodiment, the first fluidic material comprises a
hardenable fluidic sealing material such as, for example, cement or epoxy in order to
provide a hardenable outer annular body around the expanded casing 2155.
The first fluidic material maybe pumped into the fluid passage 2160 at operating
30 pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000
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gallons/minute (0 to 310.264 bar, and 0 to 11356.24 litres/minute) In a preferred
embodiment, the first fluidic material is pumped into the fluid passage 2160 at operating
pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 24 1 .3 1 6 bar and 0 to 4542.49 litres/minute) in order to optimally provide operational
5 efficiency.
The first fluidic material pumped into the fluid passage 2160 passes through the
fluid passages 2165, 2170, 2175, 2180 and then outside of the apparatus 2100. The first
fluidic material then fills the annular region between the outside of the apparatus 2 1 00 and
the interior walls of the wellbore.
10 The plug 2245 is then introduced into the fluid passage 2160. The plug 2245
lodges in the throat passage 2240 and fluidicly isolates and blocks off the fluid passage
2175. In a preferred embodiment, a couple of volumes of a non-hardenable fluidic
material are then pumped into the fluid passage 2160 in order to remove any hardenable
fluidic material contained within and to ensure that none of the fluid passages are blocked.
15 A second fluidic material is then pumped into the fluid passage 21 60. The second
fluidic material may comprise any number of conventional commercially available
materials such as, for example, drilling mud, water, drilling gases, or lubricants. In a
preferred embodiment, the second fluidic material comprises a non-hardenable fluidic
material such as, for example, water, drilling mud or lubricant in order to optimally
20 provide pressurization of the pressure chamber 2250 and minimize factional forces.
The second fluidic material may be pumped into the fluid passage 2160 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0
to 4,500 gallons/minute (0 to 3 1 0.264 bar and 0 to 1 7034. 35 litres/minute). In a preferred
embodiment, the second fluidic material is pumped into the fluid passage 2160 at
25 operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200
gallons/minute (0 to 241.316 bar and 0 to 4542.49 litres/minute) in order to optimally
provide operational efficiency.
The second fluidic material pumped into the fluid passage 2 1 60 passes through the
fluid passages 2165, 2170, and 2175 into the pressure chambers 2195 of the slips 2125,
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and into the pressure chamber 2250. Continued pumping of the second fluidic material
pressurizes the pressure chambers 2195 and 2250.
The pressurization of the pressure chambers 2195 causes the slip members 2205
to expand in the radial direction and grip the interior surface of the casing 2155. The
5 casing 2 1 55 is then preferably maintained in a substantially stationary position.
The pressurization of the pressure chamber 2250 causes the upper sealing head
2 1 30, outer sealing mandrel 2 1 40 and expansion cone 2 1 50 to move in an axial direction
relative to the casing 21 55. In this manner, the expansion cone 2150 will cause the casing
2155 to expand in the radial direction.
10 During the radial expansion process, the casing 2 1 5 5 is prevented from moving in
an upward direction by the slips 2125. A length of the casing 2155 is then expanded in
the radial direction through the pressurization of the pressure chamber 2250. The length
of the casing 2155 that is expanded during the expansion process will be proportional to
the stroke length of the upper sealing head 2130, outer sealing mandrel 2140, and
15 expansion cone 2150.
Upon the completion of a stroke, the operating pressure of the second fluidic
material is reduced and the upper sealing head 2130, outer sealing mandrel 2140, and
expansion cone 2150 drop to their rest positions with the casing 2155 supported by the
expansion cone 2150. The position of the drillpipe 2 1 05 is preferably adjusted throughout
20 the radial expansion process in order to maintain the overlapping relationship between the
thin walled sections of the lower end of the existing wellbore casing and the upper end of
the casing 2155. In a preferred embodiment, the stroking of the expansion cone 2 1 50 is
then repeated, as necessary, until the thin walled section 2265 of the upper end 2260 of the
casing 2155 is expanded into the thin walled section of the lower end of the existing
25 wellbore casing. In this manner, a wellbore casing is formed including two adjacent
sections of casing having a substantially constant inside diameter. This process may then
be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet
in length having a substantially constant inside diameter. In a preferred
embodiment, during the final stroke of the expansion cone 2150, the slips 2125 are
30 positioned as close as possible to the thin walled section 2265 of the upper end of the
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casing 2 1 55 in order minimize slippage between the casing 2 1 55 and the existing wellbore
casing at the end of the radial expansion process. Alternatively, or in addition, the outside
diameter of the annular sealing member 2270 is selected to ensure sufficient interference
fit with the inside diameter of the lower end of the existing casing to prevent axial
5 displacement of the casing 2155 during the final stroke. Alternatively, or in addition, the
outside diameter of the annular sealing member 2285 is selected to provide an interference
fit with the inside walls of the wellbore at an earlier point in the radial expansion process
so as to prevent further axial displacement of the casing 2155. In this final alternative,
the interference fit is preferably selected to permit expansion of the casing 2 1 5 5 by pulling
10 the expansion cone 2150 out of the wellbore, without having to pressurize the pressure
chamber 2250.
During the radial expansion process, the pressurized areas of the apparatus 2100
are limited to the fluid passages 2 1 60, 2 1 65, 2 1 70, and 2 1 75, the pressure chambers 2 1 95
within the slips 2 125, and the pressure chamber 2250. No fluid pressure acts directly on
15 the casing 2155. This permits the use of operating pressures higher than the casing 2155
could normally withstand.
Once the casing 2155 has been completely expanded off of the expansion cone
2150, remaining portions of the apparatus 2100 are removed from the wellbore. In a
preferred embodiment, the contact pressure between the deformed thin wall sections and
20 compressible annular members of the lower end of the existing casing and the upper end
2260 of the casing 2 1 55 ranges from about 500 to 40,000 psi (34.47 bar to 2,757.9028 bar)
in order to optimally support the casing 2155 using the existing wellbore casing.
In this manner, the casing 2 155 is radially expanded into contact with an existing
section of casing by pressurizing the interior fluid passages 2 1 60, 2 1 65, 2 1 70, and 2 1 75
25 and the pressure chamber 2250 of the apparatus 2 1 00.
In a preferred embodiment, as required, the annular body of hardenable fluidic
material is then allowed to cure to form a rigid outer annular body about the expanded
casing 2155. In the case where the casing 2155 is slotted, the cured fluidic material
preferably permeates and envelops the expanded casing 2155. The resulting new section
30 of wellbore casing includes the expanded casing 2155 and the rigid outer annular body.
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The overlapping joint between the pre-existing wellbore casing and the expanded casing
2 1 55 includes the deformed thin wall sections and the compressible outer annular bodies.
The inner diameter of the resulting combined wellbore casings is substantially constant.
In this manner, a mono-diameter wellbore casing is formed. This process of expanding
5 overlapping tubular members having thin wall end portions with compressible annular
bodies into contact can be repeated for the entire length of a wellbore. In this manner, a
mono-diameter wellbore casing can be provided for thousands of feet in a subterranean
formation.
In a preferred embodiment, as the expansion cone 2 1 50 nears the upper end of the
10 casing 2155, the operating flow rate of the second fluidic material is reduced in order to
minimize shock to the apparatus 2 1 00. In an alternative embodiment, the apparatus 2 1 00
includes a shock absorber for absorbing the shock created by the completion of the radial
expansion of the casing 2155.
In a preferred embodiment, the reduced operating pressure of the second fluidic
15 material ranges from about 1 00 to 1 ,000 psi (6.8947 to 68.947 bar) as the expansion cone
2130 nears the end of the casing 2155 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2130. In a preferred embodiment, the
operating pressure of the second fluidic material is reduced during the return stroke of the
apparatus 21 00 to the range of about 0 to 500 psi (0 to 34.47 bar) in order minimize the
20 resistance to the movement of the expansion cone 2130 during the return stroke. In a
preferred embodiment, the stroke length of the apparatus 21 00 ranges from about 1 0 to 45
feet (3.048 to 13.716 metres) in order to optimally provide equipment lengths that can be
handled by conventional oil well rigging equipment while also minimizing the frequency
at which the expansion cone 21 30 must be stopped so that the apparatus 2 100 can be re-
25 stroked.
In an alternative embodiment, at least a portion of the upper sealing head 2130
includes an expansion cone for radially expanding the casing 2 1 55 during operation of the
apparatus 2 1 00 in order to increase the surface area of the casing 2 1 55 acted upon during
the radial expansion process. In this manner, the operating pressures can be reduced.
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Alternatively, the apparatus 2100 may be used to join a first section of pipeline to
an existing section of pipeline. Alternatively, the apparatus 2 1 00 may be used to directly
line the interior of a wellbore with a casing, without the use of an outer annular layer of
a hardenable material. Alternatively, the apparatus 21 00 may be used to expand a tubular
5 support member in a hole.
Referring now to Figures 17, 17a and 17b, another embodiment of an apparatus
2300 for expanding a tubular member will be described. The apparatus 2300 preferably
includes a drillpipe 2305, an innerstring adapter 23 1 0, a sealing sleeve 23 1 5, a hydraulic
slip body 2320, hydraulic slips 2325, an inner sealing mandrel 2330, an upper sealing head
10 2335, a lower sealing head 2340, a load mandrel 2345, an outer sealing mandrel 2350, an
expansion cone 2355, a mechanical slip body 2360, mechanical slips 2365, drag blocks
2370, casing 2375, fluid passages 2380, 2385, 2390, 2395, 2400, 2405, 2410, 2415, and
2485, and mandrel launcher 2480.
The drillpipe 2305 is coupled to the innerstring adapter 23 10. During operation
15 of the apparatus 2300, the drillpipe 2305 supports the apparatus 2300. The drillpipe 2305
preferably comprises a substantially hollow tubular member or members. The drillpipe
2305 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel ,
stainless steel or other similar high strength materials. In a preferred embodiment, the
20 drillpipe 2305 is fabricated from coiled tubing in order to faciliate the placement of the
apparatus 2300 in non-vertical wellbores. The drillpipe 2305 may be coupled to the
innerstring adapter 2310 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, or a standard threaded connection. In a preferred
25 embodiment, the drillpipe 2305 is removably coupled to the innerstring adapter 23 1 0 by
a drillpipe connection.
The drillpipe 2305 preferably includes a fluid passage 2380 that is adapted to
convey fluidic materials from a surface location into the fluid passage 23 85 . In a preferred
embodiment, the fluid passage 2380 is adapted to convey fluidic materials such as, for
30 example, cement, water, epoxy, drilling muds, or lubricants at operating pressures and
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flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528
bar and 0 to 1 1356.24 litres/minute) in order to optimally provide operational efficiency.
The innerstring adapter 2310 is coupled to the drill string 2305 and the sealing
sleeve 2315. The innerstring adapter 23 10 preferably comprises a substantially hollow
5 tubular member or members. The innerstring adapter 23 1 0 may be fabricated from any
number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the innerstring adapter 23 1 0 is fabricated
from stainless steel in order to optimally provide high strength, corrosion resistance, and
10 low friction surfaces.
The innerstring adapter 23 10 may be coupled to the drill string 2305 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, or a standard threaded connection. In a preferred embodiment, the innerstring
15 adapter 23 10 is removably coupled to the drill pipe 2305 by a drillpipe connection. The
innerstring adapter 23 1 0 may be coupled to the sealing sleeve 23 1 5 using any number of
conventional commercially available mechanical couplings such as, for example, a
drillpipe connection, oilfield country tubular goods specialty threaded connection, or a
standard threaded connection. In a preferred embodiment, the innerstring adapter 2310
20 is removably coupled to the sealing sleeve 23 15 by a standard threaded connection.
The innerstring adapter 2310 preferably includes a fluid passage 2385 that is
adapted to convey fluidic materials from the fluid passage 2380 into the fluid passage
2390. In a preferred embodiment, the fluid passage 2385 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud, drilling gases or
25 lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0
to 3,000 gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The sealing sleeve 2315 is coupled to the innerstring adapter 2310 and the
hydraulic slip body 2320. The sealing sleeve 2315 preferably comprises a substantially
hollow tubular member or members. The sealing sleeve 23 1 5 may be fabricated from any
30 number of conventional commercially available materials such as, for example, oilfield
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country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the sealing sleeve 23 1 5 is fabricated from
stainless steel in order to optimally provide high strength, corrosion resistance, and low-
friction surfaces.
5 The sealing sleeve 23 1 5 may be coupled to the innerstring adapter 23 1 0 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connections, oilfield country tubular goods specialty threaded
connections, or a standard threaded connection. In a preferred embodiment, the sealing
sleeve 23 1 5 is removably coupled to the innerstring adapter 23 10 by a standard threaded
10 connection. The sealing sleeve 2315 may be coupled to the hydraulic slip body 2320
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, or a standard threaded connection. In a preferred embodiment, the sealing
sleeve 23 1 5 is removably coupled to the hydraulic slip body 2320 by a standard threaded
15 connection.
The sealing sleeve 2315 preferably includes a fluid passage 2390 that is adapted
to convey fluidic materials from the fluid passage 2385 into the fluid passage 2395. In a
preferred embodiment, the fluid passage 23 1 5 is adapted to convey fluidic materials such
as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures
20 and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356.24 litres/minute).
The hydraulic slip body 2320 is coupled to the sealing sleeve 23 15, the hydraulic
slips 2325, and the inner sealing mandrel 2330. The hydraulic slip body 2320 preferably
comprises a substantially hollow tubular member or members. The hydraulic slip body
25 2320 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel ,
stainless steel or other high strength material. In a preferred embodiment, the hydraulic
slip body 2320 is fabricated from carbon steel in order to optimally provide high strength
at low cost.
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The hydraulic slip body 2320 may be coupled to the sealing sleeve 23 1 5 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, or a standard threaded connection. In a preferred embodiment, the hydraulic
5 slip body 2320 is removably coupled to the sealing sleeve 23 1 5 by a standard threaded
connection. The hydraulic slip body 2320 may be coupled to the slips 2325 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
10 preferred embodiment, the hydraulic slip body 2320 is removably coupled to the slips
2325 by a standard threaded connection. The hydraulic slip body 2320 may be coupled
to the inner sealing mandrel 2330 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection, oilfield country
tubular goods specialty threaded connection, welding, amorphous bonding or a standard
15 threaded connection. In a preferred embodiment, the hydraulic slip body 2320 is
removably coupled to the inner sealing mandrel 2330 by a standard threaded connection.
The hydraulic slips body 2320 preferably includes a fluid passage 2395 that is
adapted to convey fluidic materials from the fluid passage 2390 into the fluid passage
2405. In a preferred embodiment, the fluid passage 2395 is adapted to convey fluidic
20 materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The hydraulic slips body 2320 preferably includes fluid passage 2400 that are
adapted to convey fluidic materials from the fluid passage 2395 into the pressure chambers
25 2420 of the hydraulic slips 2325. In this manner, the slips 2325 are activated upon the
pressurization of the fluid passage 2395 into contact with the inside surface of the casing
2375. In a preferred embodiment, the fluid passages 2400 are adapted to convey fluidic
materials such as, for example, water, drilling mud or lubricants at operating pressures and
flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528
30 bar and 0 to 1 1356.24 litres/minute).
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The slips 2325 are coupled to the outside surface of the hydraulic slip body 2320.
During operation of the apparatus 2300, the slips 2325 are activated upon the
pressurization of the fluid passage 2395 into contact with the inside surface of the casing
2375. In this manner, the slips 2325 maintain the casing 2375 in a substantially stationary
5 position.
The slips 2325 preferably include the fluid passages 2400, the pressure chambers
2420, spring bias 2425, and slip members 243 0. The slips 23 25 may comprise any number
of conventional commercially available hydraulic slips such as, for example, RTTS packer
tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips.
10 In a preferred embodiment, the slips 2325 comprise RTTS packer tungsten carbide
hydraulic slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 2375 during the radial expansion process.
The inner sealing mandrel 2330 is coupled to the hydraulic slip body 2320 and the
lower sealing head 2340. The inner sealing mandrel 2330 preferably comprises a
15 substantially hollow tubular member or members. The inner sealing mandrel 2330 may
be fabricated from any number of conventional commercially available materials such as,
for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the inner sealing
mandrel 2330 is fabricated from stainless steel in order to optimally provide high strength,
20 corrosion resistance, and low friction surfaces.
The inner sealing mandrel 2330 may be coupled to the hydraulic slip body 2320
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
25 preferred embodiment, the inner sealing mandrel 2330 is removably coupled to the
hydraulic slip body 2320 by a standard threaded connection. The inner sealing mandrel
2330 may be coupled to the lower sealing head 2340 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, welding, amorphous
30 bonding, or a standard threaded connection. In a preferred embodiment, the inner sealing
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mandrel 2330 is removably coupled to the lower sealing head 2340 by a standard threaded
connection.
The inner sealing mandrel 2330 preferably includes a fluid passage 2405 that is
adapted to convey fluidic materials from the fluid passage 2395 into the fluid passage
5 2415. In a preferred embodiment, the fluid passage 2405 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The upper sealing head 2335 is coupled to the outer sealing mandrel 2345 and
10 expansion cone 2355. The upper sealing head 2335 is also movably coupled to the outer
surface of the inner sealing mandrel 2330 and the inner surface of the casing 2375. In this
manner, the upper sealing head 2335 reciprocates in the axial direction. The radial
clearance between the inner cylindrical surface of the upper sealing head 2335 and the
outer surface of the inner sealing mandrel 2330 may range, for example, from about
15 0.0025 to 0.05 inches (0.00635 to 0.127 centimetres). In a preferred embodiment, the
radial clearance between the inner cylindrical surface of the upper sealing head 2335 and
the outer surface of the inner sealing mandrel 2330 ranges from about 0.005 to 0.0 1 inches
(0.0127 to 0.254 centimetres) in order to optimally provide minimal clearance. The radial
clearance between the outer cylindrical surface of the upper sealing head 2335 and the
20 inner surface of the casing 2375 may range, for example, from about 0.025 to 0.375 inches
(0.0635 to 0.9525 centimetres). In a preferred embodiment, the radial clearance between
the outer cylindrical surface of the upper sealing head 2335 and the inner surface of the
casing 2375 ranges from about 0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in
order to optimally provide stabilization for the expansion cone 2355 during the expansion
25 process.
The upper sealing head 2335 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The upper sealing head 2335 may be
fabricated from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or
30 other similar high strength materials. In a preferred embodiment, the upper sealing head
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2335 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The inner surface of the upper sealing
head 2335 preferably includes one or more annular sealing members 2435 for sealing the
interface between the upper sealing head 2335 and the inner sealing mandrel 2330. The
5 sealing members 2435 may comprise any number of conventional commercially available
annular sealing members such as, for example, o-rings, polypak seals or metal spring
energized seals. In a preferred embodiment, the sealing members 2435 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a long axial
stroke.
10 In a preferred embodiment, the upper sealing head 2335 includes a shoulder 2440
for supporting the upper sealing head on the lower sealing head 1 930.
The upper sealing head 2335 may be coupled to the outer sealing mandrel 2350
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty threaded
15 connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the upper sealing head 2335 is removably coupled to the outer
sealing mandrel 2350 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the upper sealing head 2335 and the outer sealing mandrel
2350 includes one or more sealing members 2445 for fluidicly sealing the interface
20 between the upper sealing head 2335 and the outer sealing mandrel 2350. The sealing
members 2445 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals or metal spring energized seals. In
a preferred embodiment, the sealing members 2445 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
25 The lower sealing head 2340 is coupled to the inner sealing mandrel 2330 and the
load mandrel 2345. The lower sealing head 2340 is also movably coupled to the inner
surface of the outer sealing mandrel 2350. In this manner, the upper sealing head 2335
and outer sealing mandrel 2350 reciprocate in the axial direction. The radial clearance
between the outer surface of the lower sealing head 2340 and the inner surface of the
30 outer scaling mandrel 2350 may range, for example, from about 0.0025 to 0.05 inches
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(0.00635 to 0. 1 27 centimetres). In a preferred embodiment, the radial clearance between
the outer surface of the lower sealing head 2340 and the inner surface of the outer sealing
mandrel 2350 ranges from about 0.005 to 0.010 inches (0.0127 to 0.0254 centimetres) in
order to optimally provide minimal radial clearance.
5 The lower sealing head 2340 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The lower sealing head 2340 may be
fabricated from any number of conventional commercially available materials such as, for
example, oilfield tubular members, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the lower sealing head 2340
10 is fabricated from stainless steel in order to optimally provide high strength, corrosion
resistance, and low friction surfaces. The outer surface of the lower sealing head 2340
preferably includes one or more annular sealing members 2450 for sealing the interface
between the lower sealing head 2340 and the outer sealing mandrel 2350. The sealing
members 2450 may comprise any number of conventional commercially available annular
15 sealing members such as, for example, o-rings, polypak seals or metal spring energized
seals. In a preferred embodiment, the sealing members 2450 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 2340 may be coupled to the inner sealing mandrel 2330
using any number of conventional commercially available mechanical couplings such as,
20 for example, drillpipe connection, oilfield country tubular specialty threaded connection,
welding, amorphous bonding, or standard threaded connection. In a preferred
embodiment, the lower sealing head 2340 is removably coupled to the inner sealing
mandrel 2330 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the lower sealing head 2340 and the inner sealing mandrel
25 2330 includes one or more sealing members 2455 for fluidicly sealing the interface
between the lower sealing head 2340 and the inner sealing mandrel 2330. The sealing
members 2455 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak or metal spring energized seals. In a
preferred embodiment, the sealing members 2455 comprise polypak seals available from
30 Parker Seals in order to optimally provide sealing for a long axial stroke length.
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The lower sealing head 2340 may be coupled to the load mandrel 2345 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
5 preferred embodiment, the lower sealing head 2340 is removably coupled to the load
mandrel 2345 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the lower sealing head 2340 and the load mandrel 2345
includes one or more sealing members 2460 for fluidicly sealing the interface between the
lower sealing head 2340 and the load mandrel 2345. The sealing members 2460 may
10 comprise any number of conventional commercially available sealing members such as,
for example, o-rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2460 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial stroke length.
In a preferred embodiment, the lower sealing head 2340 includes a throat passage
15 2465 fluidicly coupled between the fluid passages 2405 and 2415. The throat passage
2465 is preferably of Teduced size and is adapted to receive and engage with a plug 2470,
or other similar device. In this manner, the fluid passage 2405 is fluidicly isolated from
the fluid passage 241 5. In this manner, the pressure chamber 2475 is pressurized.
The outer sealing mandrel 2350 is coupled to the upper sealing head 2335 and the
20 expansion cone 2355. The outer sealing mandrel 2350 is also movably coupled to the
inner surface of the casing 2375 and the outer surface of the lower sealing head 2340. In
this manner, the upper sealing head 2335, outer sealing mandrel 2350, and the expansion
cone 2355 reciprocate in the axial direction. The radial clearance between the outer
surface of the outer sealing mandrel 2350 and the inner surface of the casing 2375 may
25 range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In
a preferred embodiment, the radial clearance between the outer surface of the outer sealing
mandrel 2350 and the inner surface of the casing 2375 ranges from about 0.025 to 0.125
inches (0.0635 to 0.3 175 centimetres) in order to optimally provide stabilization for the
expansion cone 2355 during the expansion process. The radial clearance between the
30 inner surface of the outer sealing mandrel 2350 and the outer surface of the lower sealing
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head 2340 may range, for example, from about 0.0025 to 0.375 inches (0.0635 to 0.9525
centimetres). In a preferred embodiment, the radial clearance between the inner surface
of the outer sealing mandrel 2350 and the outer surface of the lower sealing head 2340
ranges from about 0.005 to 0.010 inches (0.0127 to 0.0254 centimetres) in order to
5 optimally provide minimal clearance.
The outer sealing mandrel 2350 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The outer sealing mandrel 2350 may
be fabricated from any number of conventional commercially available materials such as,
for example, low alloy steel, carbon steel, stainless steel or other similar high strength
10 materials. In a preferred embodiment, the outer sealing mandrel 2350 is fabricated from
stainless steel in order to optimally provide high strength, corrosion resistance, and low
friction surfaces.
The outer sealing mandrel 2350 may be coupled to the upper sealing head 2335
using any number of conventional commercially available mechanical couplings such as,
15 for example, drillpipe connections, oilfield country tubular goods specialty threaded
connections, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the outer sealing mandrel 2350 is removably coupled to the upper
sealing head 2335 by a standard threaded connection. The outer sealing mandrel 2350
may be coupled to the expansion cone 2355 using any number of conventional
20 commercially available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, welding, amorphous
bonding, or a standard threaded connection. In a preferred embodiment, the outer sealing
mandrel 2350 is removably coupled to the expansion cone 2355 by a standard threaded
connection.
25 The upper sealing head 2335, the lower sealing head 2340, the inner sealing
mandrel 2330, and the outer sealing mandrel 2350 together define a pressure chamber
2475. The pressure chamber 2475 is fluidicly coupled to the passage 2405 via one or
more passages 241 0. During operation of the apparatus 2300, the plug 2470 engages with
the throat passage 2465 to fluidicly isolate the fluid passage 2415 from the fluid passage
30 2405. The pressure chamber 2475 is then pressurized which in turn causes the upper
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sealing head 2335, outer sealing mandrel 2350, and expansion cone 2355 to reciprocate
in the axial direction. The axial motion of the expansion cone 2355 in turn expands the
casing 2375 in the radial direction.
The load mandrel 2345 is coupled to the lower sealing head 2340 and the
5 mechanical slip body 2360. The load mandrel 2345 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The load mandrel 2345
may be fabricated from any number of conventional commercially available materials such
as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the load mandrel
10 2345 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The load mandrel 2345 may be coupled to the lower sealing head 2340 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
15 connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the load mandrel 2345 is removably coupled to the lower sealing
head 2340 by a standard threaded connection. The load mandrel 2345 may be coupled to
the mechanical slip body 2360 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
20 goods specialty threaded connection, welding, amorphous bonding, or a standard threaded
connection. In a preferred embodiment, the load mandrel 2345 is removably coupled to
the mechanical slip body 2360 by a standard threaded connection.
The load mandrel 2345 preferably includes a fluid passage 24 1 5 that is adapted to
convey fluidic materials from the fluid passage 2405 to the region outside of the apparatus
25 2300. In a preferred embodiment, the fluid passage 2415 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The expansion cone 2355 is coupled to the outer sealing mandrel 2350. The
30 expansion cone 2355 is also movably coupled to the inner surface of the casing 2375. In
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this manner, the upper sealing head 2335, outer sealing mandrel 2350, and the expansion
cone 2355 reciprocate in the axial direction. The reciprocation of the expansion cone
2355 causes the casing 2375 to expand in the radial direction.
The expansion cone 2355 preferably comprises an annular member having
5 substantially cylindrical inner and conical outer surfaces . The outside radius of the outside
conical surface may range, for example, from about 2 to 34 inches (5.08 to 86.36
centimetres). In a preferred embodiment, the outside radius of the outside conical surface
ranges from about 3 to 28 inches (7.62 to 7 1 . 12 centimetres) in order to optimally provide
radial expansion of the typical casings. The axial length of the expansion cone 2355 may
10 range, for example, from about 2 to 8 times the largest outside diameter of the expansion
cone 2355. In a preferred embodiment, the axial length of the expansion cone 2355 ranges
from about 3 to 5 times the largest outside diameter of the expansion cone 2355 in order
to optimally provide stability and centralization of the expansion cone 2355 during the
expansion process. In a preferred embodiment, the angle of attack of the expansion cone
15 2355 ranges from about 5 to 30 degrees in order to optimally frictional forces with radial
expansion forces. The optimum angle of attack of the expansion cone 2355 will vary as
a function of the operating parameters of the particular expansion operation.
The expansion cone 2355 may be fabricated from any number of conventional
commercially available materials such as, for example, machine tool steel, nitride steel,
20 titanium, tungsten carbide, ceramics or other similar high strength materials. In a
preferred embodiment, the expansion cone 2355 is fabricated from D2 machine tool steel
in order to optimally provide high strength, abrasion resistance, and galling resistance.
In aparticularly preferred embodiment, the outside surface of the expansion cone 2355 has
a surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
25 high strength, abrasion resistance, resistance to galling.
The expansion cone 2355 may be coupled to the outside sealing mandrel 2350
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
30 preferred embodiment, the expansion cone 2355 is coupled to the outside sealing mandrel
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2350 using a standard threaded connection in order to optimally provide high strength and
permit the expansion cone 2355 to be easily replaced.
The mandrel launcher 2480 is coupled to the casing 2375. The mandrel launcher
2480 comprises a tubular section of casing having a reduced wall thickness compared to
5 the casing 2375. In a preferred embodiment, the wall thickness of the mandrel launcher
2480 is about 50 to 100 % of the wall thickness of the casing 2375. In this manner, the
initiation of the radial expansion of the casing 2375 is facilitated, and the placement of the
apparatus 2300 into a wellbore casing and wellbore is facilitated.
The mandrel launcher 2480 may be coupled to the casing 2375 using any number
10 of conventional mechanical couplings. The mandrel launcher 2480 may have a wall
thickness ranging, for example, from about 0. 1 5 to 1 .5 inches (0.38 1 to 3.8 1 centimetres).
In a preferred embodiment, the wall thickness of the mandrel launcher 2480 ranges from
about 0.25 to 0.75 inches (0.635 to 1.905 centimetres) in order to optimally provide high
strength in a minimal profile. The mandrel launcher 2480 may be fabricated from any
15 number of conventional commercially available materials such as, for example, oilfield
tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength
materials. In a preferred embodiment, the mandrel launcher 2480 is fabricated from
oilfield tubular goods having a higher strength than that of the casing 2375 but with a
smaller wall thickness than the casing 2375 in order to optimally provide a thin walled
20 container having approximately the same burst strength as that of the casing 2375.
The mechanical slip body 2460 is coupled to the load mandrel 2345, the
mechanical slips 2365, and the drag blocks 2370. The mechanical slip body 2460
preferably comprises a tubular member having an inner passage 2485 fluidicly coupled
to the passage 24 1 5. In this manner, fluidic materials may be conveyed from the passage
25 2484 to a region outside of the apparatus 2300.
The mechanical slip body 2360 maybe coupled to the load mandrel 2345 using any
number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 2360 is removably coupled to the load mandrel 2345 using threads
and sliding steel retaining rings in order to optimally provide a high strength attachment.
30 The mechanical slip body 2360 may be coupled to the mechanical slips 2365 using any
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number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 2360 is removably coupled to the mechanical slips 2365 using
threads and sliding steel retaining rings in order to optimally provide a high strength
attachment. The mechanical slip body 23 60 may be coupled to the drag blocks 2370 using
5 any number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 2360 is removably coupled to the drag blocks 2365 using threads
and sliding steel retaining rings in order to optimally provide a high strength attachment.
The mechanical slips 2365 are coupled to the outside surface of the mechanical slip
body 2360. During operation of the apparatus 2300, the mechanical slips 2365 prevent
10 upward movement of the casing 2375 and mandrel launcher 2480. In this manner, during
the axial reciprocation of the expansion cone 2355, the casing 2375 and mandrel launcher
2480 are maintained in a substantially stationary position. In this manner, the mandrel
launcher 2480 and casing 2375 are expanded in the radial direction by the axial movement
of the expansion cone 2355.
15 The mechanical slips 2365 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer tungsten
carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L
retrievable bridge plug tungsten carbide upper mechanical slips. In a preferred
embodiment, the mechanical slips 2365 comprise RTTS packer tungsten carbide
20 mechanical slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 2375 during the expansion process.
The drag blocks 2370 are coupled to the outside surface of the mechanical slip
body 2360. During operation of the apparatus 2300, the drag blocks 2370 prevent upward
movement of the casing 2375 and mandrel launcher 2480. In this manner, during the axial
25 reciprocation of the expansion cone 2355, the casing 2375 and mandrel launcher 2480 are
maintained in a substantially stationary position. In this manner, the mandrel launcher
2480 and casing 2375 are expanded in the radial direction by the axial movement of the
expansion cone 2355.
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The drag blocks 2370 may comprise any number of conventional commercially
available mechanical slips such as, for example, RTTS packer mechanical drag blocks or
Model 3L retrievable bridge plug drag blocks. In a preferred embodiment, the drag blocks
2370 comprise RTTS packer mechanical drag blocks available from Halliburton Energy
5 Services in order to optimally provide resistance to axial movement of the casing 2375
during the expansion process.
The casing 2375 is coupled to the mandrel launcher 2480. The casing 2375 is
further removably coupled to the mechanical slips 2365 and drag blocks 2370. The casing
2375 preferably comprises a tubular member. The casing 2375 may be fabricated from
10 anynumber of conventional commercially available materials such as, for example, slotted
tubulars, oil country tubular goods, carbon steel, low alloy steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the casing 2375 is fabricated
from oilfield country tubular goods available from various foreign and domestic steel mills
in order to optimally provide high strength. In a preferred embodiment, the upper end of
1 5 the casing 2375 includes one or more sealing members positioned about the exterior of the
casing 2375.
During operation, the apparatus 2300 is positioned in a wellbore with the upper end
of the casing 2375 positioned in an overlapping relationship within an existing wellbore
casing. In order minimize surge pressures within the borehole during placement of the
20 apparatus 2300, the fluid passage 2380 is preferably provided with one or more pressure
relief passages. During the placement of the apparatus 2300 in the wellbore, the casing
2375 is supported by the expansion cone 2355.
After positioning of the apparatus 2300 within the bore hole in an overlapping
relationship with an existing section of wellbore casing, a first fluidic material is pumped
25 into the fluid passage 2380 from a surface location. The first fluidic material is conveyed
from the fluid passage 2380 to the fluid passages 23 85, 2390, 2395 , 2405, 241 5, and 2485.
The first fluidic material will then exit the apparatus 2300 and fill the annular region
between the outside of the apparatus 2300 and the interior walls of the bore hole.
The first fluidic material may comprise anynumber of conventional commercially
30 available materials such as, for example, cpoxy, drilling mud, slag mix, cement, or water.
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In a preferred embodiment, the first fluidic material comprises a hardenable fluidic sealing
material such as, for example, slag mix, epoxy, or cement. In this manner, a wellbore
casing having an outer annular layer of a hardenable material may be formed.
The first fluidic material may be pumped into the apparatus 2300 at operating
5 pressures and flow rates ranging, for example, from about 0 to 4,500 psi, and 0 to 3,000
gallons/minute (0 to 310.264 bar, and 0 to 11356.24 litres/minute). In a preferred
embodiment, the first fluidic material is pumped into the apparatus 2300 at operating
pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 24 1 .3 1 6 bar and 0 to 4542.49 litres/minute) in order to optimally provide operational
10 efficiency.
At a predetermined point in the injection of the first fluidic material such as, for
example, after the annular region outside of the apparatus 2300 has been filled to a
predetermined level, a plug 2470, dart, or other similar device is introduced into the first
fluidic material. The plug 2470 lodges in the throat passage 2465 thereby fluidicly
15 isolating the fluid passage 2405 from the fluid passage 2415.
After placement of the plug 2470 in the throat passage 2465, a second fluidic
material is pumped into the fluid passage 23 80 in order to pressurize the pressure chamber
2475. The second fluidic material may comprise any number of conventional
commercially available materials such as, for example, water, drilling gases, drilling mud
20 or lubricants. In a preferred embodiment, the second fluidic material comprises a non-
hardenable fluidic material such as, for example, water, drilling mud or lubricant.
The second fluidic material may be pumped into the apparatus 2300 at operating
pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500
gallons/minute (0 to 310.264 bar and 0 to 17034.35 litres/minute). In a preferred
25 embodiment, the second fluidic material is pumped into the apparatus 2300 at operating
pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 241 .3 1 6 bar and 0 to 4542.49 litres/minute) in order to optimally provide operational
efficiency.
The pressurization of the pressure chamber 2475 causes the upper sealing head
30 2335, outer sealing mandrel 2350, and expansion cone 2355 to move in an axial direction.
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The pressurization of the pressure chamber 2475 also causes the hydraulic slips 2325 to
expand in the radial direction and hold the casing 2375 in a substantially stationary
position. Furthermore, as the expansion cone 2355 moves in the axial direction, the
expansion cone 2355 pulls the mandrel launcher 2480 and drag blocks 2370 along, which
5 sets the mechanical slips 2365 and stops further axial movement of the mandrel launcher
2480 and casing 2375. In this manner, the axial movement of the expansion cone 2355
radially expands the mandrel launcher 2480 and casing 2375.
Once the upper sealing head 2335, outer sealing mandrel 2350, and expansion cone
2355 complete an axial stroke, the operating pressure of the second fluidic material is
10 reduced. The reduction in the operating pressure of the second fluidic material releases
the hydraulic slips 2325. The drill string 2305 is then raised. This causes the inner sealing
mandrel 2330, lower sealing head 2340, load mandrel 2345, and mechanical slip body
2360 to move upward. This unsets the mechanical slips 2365 and permits the mechanical
slips 2365 and drag blocks 2370 to be moved within the mandrel launcher 2480 and casing
15 2375. When the lower sealing head 2340 contacts the upper sealing head 2335, the second
fluidic material is again pressurized and the radial expansion process continues. In this
manner, the mandrel launcher 2480 and casing 2375 are radial expanded through repeated
axial strokes of the upper sealing head 2335, outer sealing mandrel 2350 and expansion
cone 2355. Throughput the radial expansion process, the upper end of the casing 2375 is
20 preferably maintained in an overlapping relation with an existing section of wellbore
casing.
At the end of the radial expansion process, the upper end of the casing 2375 is
expanded into intimate contact with the inside surface of the lower end of the existing
wellbore casing. In a preferred embodiment, the sealing members provided at the upper
25 end of the casing 2375 provide a fluidic seal between the outside surface of the upper end
of the casing 2375 and the inside surface of the lower end of the existing wellbore casing.
In a preferred embodiment, the contact pressure between the casing 2375 and the existing
section of wellbore casing ranges from about 400 to 10,000 psi (27.58 to 689.476 bar) in
order to optimally provide contact pressure, activate the sealing members, and withstand
30 typical tensile and compressive loading conditions.
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In a preferred embodiment, as the expansion cone 2355 nears the upper end of the
casing 2375, the operating pressure of the second fluidic material is reduced in order to
minimize shock to the apparatus 2300. In an alternative embodiment, the apparatus 2300
includes a shock absorber for absorbing the shock created by the completion of the radial
5 expansion of the casing 2375.
In a preferred embodiment, the reduced operating pressure of the second fluidic
material ranges from about 100 to 1 ,000 psi (6.8947 to 68.947 bar) as the expansion cone
2355 nears the end of the casing 2375 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2355. In a preferred embodiment, the
10 operating pressure of the second fluidic material is reduced during the return stroke of the
apparatus 2300 to the range of about 0 to 500 psi (0 to 34.47 bar) in order minimize the
resistance to the movement of the expansion cone 2355 during the return stroke. In a
preferred embodiment, the stroke length of the apparatus 2300 ranges from about 10 to 45
feet (3.048 to 1 3 .7 1 6 metres) in order to optimally provide equipment that can be handled
15 by typical oil well rigging equipment and minimize the frequency at which the expansion
cone 2355 must be stopped to permit the apparatus 2300 to be re-stroked.
In an alternative embodiment, at least a portion of the upper sealing head 2335
includes an expansion cone for radially expanding the mandrel launcher 2480 and casing
2375 during operation of the apparatus 2300 in order to increase the surface area of the
20 casing 23 75 acted upon during the radial expansion process. In this manner, the operating
pressures can be reduced.
In an alternative embodiment, mechanical slips 2365 are positioned in an axial
location between the sealing sleeve 2315 and the inner sealing mandrel 2330 in order to
optimally the construction and operation of the apparatus 2300.
25 Upon the complete radial expansion of the casing 2375, if applicable, the first
fluidic material is permitted to cure within the annular region between the outside of the
expanded casing 2375 and the interior walls of the wellbore. In the case where the casing
2375 is slotted, the cured fluidic material preferably permeates and envelops the expanded
casing 2375. In this manner, a new section of wellbore casing is formed within a
30 wellbore. Alternatively, the apparatus 2300 may be used to join a first section of pipeline
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to an existing section of pipeline. Alternatively, the apparatus 2300 may be used to
directly line the interior of a wellbore with a casing, without the use of an outer annular
layer of a hardenable material Alternatively, the apparatus 2300 may be used to expand
a tubular support member in a hole.
5 During the radial expansion process, the pressurized areas of the apparatus 2300
are limited to the fluid passages 2380, 2385, 2390, 2395, 2400, 2405, and 2410, and the
pressure chamber 2475. No fluid pressure acts directly on the mandrel launcher 2480 and
casing 23 75 . This permits the use of operating pressures higher than the mandrel launcher
2480 and casing 2375 could normally withstand.
10 Referring now to Figure 18, a preferred embodiment of an apparatus 2500 for
forming a mono-diameter wellbore casing will be described. The apparatus 2500
preferably includes a drillpipe 2505, an innerstring adapter 2510, a sealing sleeve 2515,
a hydraulic slip body 2520, hydraulic slips 2525, an inner sealing mandrel 2530, upper
sealing head 2535, lower sealing head 2540, outer sealing mandrel 2545, load mandrel
15 2550, expansion cone 2555, casing 2560, and fluid passages 2565, 2570, 2575, 2580,
2585,2590, 2595, and 2600.
The drillpipe 2505 is coupled to the innerstring adapter 2510. During operation
of the apparatus 2500, the drillpipe 2505 supports the apparatus 2500. The drillpipe 2505
preferably comprises a substantially hollow tubular member or members. The drillpipe
20 2505 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
drillpipe 2505 is fabricated from coiled tubing in order to faciliate the placement of the
apparatus 2500 in non-vertical wellbores. The drillpipe 2505 may be coupled to the
25 innerstring adapter 2510 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, or a standard threaded connection. In a preferred
embodiment, the drillpipe 2505 is removably coupled to the innerstring adapter 25 1 0 by
a drillpipe connection, a drillpipe connection provides the advantages of high strength and
30 easy disassembly.
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The drillpipe 2505 preferably includes a fluid passage 2565 that is adapted to
convey fluidic materials from a surface location into the fluid passage 2570. In a preferred
embodiment, the fluid passage 2565 is adapted to convey fluidic materials such as, for
example, cement, epoxy, water, drilling mud, or lubricants at operating pressures and flow
5 rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528 bar
and 0 to 1 1356.24 litres/minute).
The innerstring adapter 2510 is coupled to the drill string 2505 and the sealing
sleeve 2515. The innerstring adapter 2510 preferably comprises a substantially hollow
tubular member or members. The innerstring adapter 25 10 may be fabricated from any
10 number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the innerstring adapter 25 10 is fabricated
from stainless steel in order to optimally provide high strength, corrosion resistance, and
low friction surfaces.
15 The innerstring adapter 2510 may be coupled to the drill string 2505 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, or a standard threaded connection. In a preferred embodiment, the innerstring
adapter 2510 is removably coupled to the drill pipe 2505 by a drillpipe connection. The
20 innerstring adapter 2510 may be coupled to the sealing sleeve 25 1 5 using any number of
conventional commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch
type threaded connection or a standard threaded connection. In a preferred embodiment,
the innerstring adapter 25 1 0 is removably coupled to the sealing sleeve 25 1 5 by a standard
25 threaded connection.
The innerstring adapter 2510 preferably includes a fluid passage 2570 that is
adapted to convey fluidic materials from the fluid passage 2565 into the fluid passage
2575. In a preferred embodiment, the fluid passage 2570 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
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operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The sealing sleeve 2515 is coupled to the innerstring adapter 2510 and the
hydraulic slip body 2520. The sealing sleeve 25 1 5 preferably comprises a substantially
5 hollow tubular member or members. The sealing sleeve 25 1 5 may be fabricated from any
number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the sealing sleeve 25 1 5 is fabricated from
stainless steel in order to optimally provide high strength, corrosion resistance, and low-
10 friction surfaces.
The sealing sleeve 2515 may be coupled to the innerstring adapter 25 1 0 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connections, oilfield country tubular goods specialty type threaded
connection, ratchet-latch type threaded connection, or a standard threaded connection. In
15 a preferred embodiment, the sealing sleeve 25 1 5 is removably coupled to the innerstring
adapter 25 1 0 by a standard threaded connection. The sealing sleeve 25 1 5 may be coupled
to the hydraulic slip body 2520 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, ratchet-latch type threaded connection, or a
20 standard threaded connection. In a preferred embodiment, the sealing sleeve 2515 is
removably coupled to the hydraulic slip body 2520 by a standard threaded connection.
The sealing sleeve 2515 preferably includes a fluid passage 2575 that is adapted
to convey fluidic materials from the fluid passage 2570 into the fluid passage 2580. In a
preferred embodiment, the fluid passage 2575 is adapted to convey fluidic materials such
25 as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures
and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356.24 litres/minute).
The hydraulic slip body 2520 is coupled to the sealing sleeve 2515, the hydraulic
slips 2525, and the inner sealing mandrel 2530. The hydraulic slip body 2520 preferably
30 comprises a substantially hollow tubular member or members. The hydraulic slip body
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2520 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
hydraulic slip body 2520 is fabricated from carbon steel in order to optimally provide high
5 strength.
The hydraulic slip body 2520 may be coupled to the sealing sleeve 25 1 5 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, ratchet-latch type threaded connection or a standard threaded connection. In
10 a preferred embodiment, the hydraulic slip body 2520 is removably coupled to the sealing
sleeve 2515 by a standard threaded connection. The hydraulic slip body 2520 may be
coupled to the slips 2525 using any number of conventional commercially available
mechanical couplings such as, for example, threaded connection or welding. In a
preferred embodiment, the hydraulic slip body 2520 is removably coupled to the slips
15 2525 by a threaded connection. The hydraulic slip body 2520 may be coupled to the inner
sealing mandrel 2530 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the hydraulic slip body 2520 is
20 removably coupled to the inner sealing mandrel 2530 by a standard threaded connection.
The hydraulic slips body 2520 preferably includes a fluid passage 2580 that is
adapted to convey fluidic materials from the fluid passage 2575 into the fluid passage
2590. In a preferred embodiment, the fluid passage 2580 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
25 operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The hydraulic slips body 2520 preferably includes fluid passages 2585 that are
adapted to convey fluidic materials from the fluid passage 2580 into the pressure chambers
of the hydraulic slips 2525. In this manner, the slips 2525 are activated upon the
30 pressurization of the fluid passage 2580 into contact with the inside surface of the casing
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2560. In a preferred embodiment, the fluid passages 2585 are adapted to convey fluidic
materials such as, for example, water, drilling mud or lubricants at operating pressures and
flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528
bar and 0 to 1 1 356.24 litres/minute).
5 The slips 2525 are coupled to the outside surface of the hydraulic slip body 2520.
During operation of the apparatus 2500, the slips 2525 are activated upon the
pressurization of the fluid passage 2580 into contact with the inside surface of the casing
2560. In this manner, the slips 2525 maintain the casing 2560 in a substantially stationary
position.
10 The slips 2525 preferably include the fluid passages 2585, the pressure chambers
2605, spring bias 26 1 0, and slip members 26 1 5. The slips 2525 may comprise any number
of conventional commercially available hydraulic slips such as, for example, RTTS packer
tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips.
In a preferred embodiment, the slips 2525 comprise RTTS packer tungsten carbide
15 hydraulic slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 2560 during the expansion process.
The inner sealing mandrel 2530 is coupled to the hydraulic slip body 2520 and the
lower sealing head 2540. The inner sealing mandrel 2530 preferably comprises a
substantially hollow tubular member or members. The inner sealing mandrel 2530 may
20 be fabricated from any number of conventional commercially available materials such as,
for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the inner sealing
mandrel 2530 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
25 The inner sealing mandrel 2530 may be coupled to the hydraulic slip body 2520
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the inner sealing mandrel 2530 is removably coupled to the
30 hydraulic slip body 2520 by a standard threaded connection. The inner sealing mandrel
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2530 may be coupled to the lower sealing head 2540 using any number of conventional
commercially available mechanical couplings such as, for example, oilfield country
tubular goods specialty type threaded connection, drillpipe connection, welding,
amorphous bonding, or a standard threaded connection. In a preferred embodiment, the
5 inner sealing mandrel 2530 is removably coupled to the lower sealing head 2540 by a
standard threaded connection.
The inner sealing mandrel 2530 preferably includes a fluid passage 2590 that is
adapted to convey fluidic materials from the fluid passage 2580 into the fluid passage
2600. In a preferred embodiment, the fluid passage 2590 is adapted to convey fluidic
10 materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The upper sealing head 2535 is coupled to the outer sealing mandrel 2545 and
expansion cone 2555. The upper sealing head 2535 is also movably coupled to the outer
15 surface of the inner sealing mandrel 2530 and the inner surface of the casing 2560. In this
manner, the upper sealing head 2535 reciprocates in the axial direction. The radial
clearance between the inner cylindrical surface of the upper sealing head 2535 and the
outer surface of the inner sealing mandrel 2530 may range, for example, from about
0.0025 to 0.05 inches (0.00635 to 0.127 centimetres). In a preferred embodiment, the
20 radial clearance between the inner cylindrical surface of the upper sealing head 2535 and
the outer surface of the inner sealing mandrel 2530 ranges from about 0.005 to 0.01 inches
(0.0 1 27 to 0.254 centimetres) in order to optimally provide minimal radial clearance. The
radial clearance between the outer cylindrical surface of the upper sealing head 2535 and
the inner surface of the casing 2560 may range, for example, from about 0.025 to 0.375
25 inches (0.0635 to 0.9525 centimetres). In a preferred embodiment, the radial clearance
between the outer cylindrical surface of the upper sealing head 2535 and the inner surface
of the casing 2560 ranges from about 0.025 to 0. 125 inches (0.0635 to 0.3 175 centimetres)
in order to optimally provide stabilization for the expansion cone 2535 during the
expansion process. The upper sealing head 2535 preferably comprises an annular
30 member having substantially cylindrical inner and outer surfaces. The upper sealing head
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2535 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, ow alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
upper sealing head 2535 is fabricated from stainless steel in order to optimally provide
5 high strength, corrosion resistance, and low friction surfaces. The inner surface of the
upper sealing head 2535 preferably includes one or more annular sealing members 2620
for sealing the interface between the upper sealing head 2535 and the inner sealing
mandrel 2530, The sealing members 2620 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings, polypak
10 seals, or metal spring energized seals. In a preferred embodiment, the sealing members
2620 comprise polypak seals available from Parker Seals in order to optimally provide
sealing for a long axial stroke.
In a preferred embodiment, the upper sealing head 2535 includes a shoulder 2625
for supporting the upper sealing head 2535, outer sealing mandrel 2545, and expansion
15 cone 2555 on the lower sealing head 2540.
The upper sealing head 2535 may be coupled to the outer sealing mandrel 2545
using any number of conventional commercially available mechanical couplings such as,
for example, oilfield country tubular goods specialty threaded connection, pipeline
connection, welding, amorphous bonding, or a standard threaded connection. In a
20 preferred embodiment, the upper sealing head 2535 is removably coupled to the outer
sealing mandrel 2545 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the upper sealing head 2535 and the outer sealing mandrel
2545 includes one or more sealing members 2630 for fluidicly sealing the interface
between the upper sealing head 2535 and the outer sealing mandrel 2545. The sealing
25 members 2630 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals or metal spring energized seals. In
a preferred embodiment, the sealing members 2630 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 2540 is coupled to the inner sealing mandrel 2530 and the
30 load mandrel 2550. The lower sealing head 2540 is also movably coupled to the inner
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surface of the outer sealing mandrel 2545. In this manner, the upper sealing head 2535,
outer sealing mandrel 2545, and expansion cone 2555 reciprocate in the axial direction.
The radial clearance between the outer surface of the lower sealing head 2540 and
the inner surface of the outer sealing mandrel 2545 may range, for example, from about
5 0,0025 to 0.05 inches (0.00635 to 0.127 centimetres). In a preferred embodiment, the
radial clearance between the outer surface of the lower sealing head 2540 and the inner
surface of the outer sealing mandrel 2545 ranges from about 0.005 to 0.01 inches (0.0127
to 0.254 centimetres) in order to optimally provide minimal radial clearance.
The lower sealing head 2540 preferably comprises an annular member having
10 substantially cylindrical inner and outer surfaces. The lower sealing head 2540 may be
fabricated from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or
other similar high strength materials. In a preferred embodiment, the lower sealing head
2540 is fabricated from stainless steel in order to optimally provide high strength,
15 corrosion resistance, and low friction surfaces. The outer surface of the lower sealing
head 2540 preferably includes one or more annular sealing members 2635 for sealing the
interface between the lower sealing head 2540 and the outer sealing mandrel 2545. The
sealing members 2635 may comprise any number of conventional commercially available
annular sealing members such as, for example, o-rings, polypak seals, or metal spring
20 energized seals. In a preferred embodiment, the sealing members 263 5 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a long axial
stroke.
The lower sealing head 2540 may be coupled to the inner sealing mandrel 2530
using any number of conventional commercially available mechanical couplings such as,
25 for example, drillpipe connections, oilfield country tubular goods specialty threaded
connection, or a standard threaded connection. In a preferred embodiment, the lower
sealing head 2540 is removably coupled to the inner sealing mandrel 2530 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 2540 and the inner sealing mandrel 2530 includes one or more sealing
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members 2640 for fluidicly sealing the interface between the lower sealing head 2540 and
the inner sealing mandrel 2530. The sealing members 2640 may comprise any number of
conventional commercially available sealing members such as, for example > o-rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the sealing
5 members 2640 comprise polypak seals available from Parker Seals in order to optimally
provide sealing for a long axial stroke.
The lower sealing head 2540 may be coupled to the load mandrel 2550 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
10 connection, welding, amorphous bonding or a standard threaded connection. In a
preferred embodiment, the lower sealing head 2540 is removably coupled to the load
mandrel 2550 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the lower sealing head 2540 and the load mandrel 2550
includes one or more sealing members 2645 for fluidicly sealing the interface between the
15 lower sealing head 2540 and the load mandrel 2550. The sealing members 2645 may
comprise any number of conventional commercially available sealing members such as,
for example, o-rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2645 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial stroke.
20 In a preferred embodiment, the lower sealing head 2540 includes a throat passage
2650 fluidicly coupled between the fluid passages 2590 and 2600. The throat passage
2650 is preferably of reduced size and is adapted to receive and engage with a plug 2655,
or other similar device. In this manner, the fluid passage 2590 is fluidicly isolated from
the fluid passage 2600. In this manner, the pressure chamber 2660 is pressurized.
25 The outer sealing mandrel 2545 is coupled to the upper sealing head 253 5 and the
expansion cone 2555. The outer sealing mandrel 2545 is also movably coupled to the
inner surface of the casing 2560 and the outer surface of the lower sealing head 2540. In
this manner, the upper sealing head 2535, outer sealing mandrel 2545, and the expansion
cone 2555 reciprocate in the axial direction. The radial clearance between the outer
30 surface of the outer sealing mandrel 2545 and the inner surface of the casing 2560 may
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range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In
a preferred embodiment, the radial clearance between the outer surface of the outer sealing
mandrel 2545 and the inner surface of the casing 2560 ranges from about 0.025 to 0.125
inches (0.0635 to 0.3 175 centimetres) in order to optimally provide stabilization for the
5 expansion cone 2535 during the expansion process. The radial clearance between the
inner surface of the outer sealing mandrel 2545 and the outer surface of the lower sealing
head 2540 may range, for example, from about 0.005 to 0.01 inches (0.0127 to 0.254
centimetres). In a preferred embodiment, the radial clearance between the inner surface
of the outer sealing mandrel 2545 and the outer surface of the lower sealing head 2540
10 ranges from about 0.005 to 0.01 inches (0.01 27 to 0.254 centimetres) in order to optimally
provide minimal radial clearance.
The outer sealing mandrel 2545 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The outer sealing mandrel 2545 may
be fabricated from any number of conventional commercially available materials such as,
15 for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the outer sealing
mandrel 2545 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The outer sealing mandrel 2545 may be coupled to the upper sealing head 2535
20 using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the outer sealing mandrel 2545 is removably coupled to the upper
sealing head 2535 by a standard threaded connection. The outer sealing mandrel 2545
25 may be coupled to the expansion cone 2555 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, welding, amorphous
bonding, or a standard threaded connection. In a preferred embodiment, the outer sealing
mandrel 2545 is removably coupled to the expansion cone 2555 by a standard threaded
30 connection.
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The upper sealing head 2535, the lower sealing head 2540, the inner sealing
mandrel 2530, and the outer sealing mandrel 2545 together define a pressure chamber
2660. The pressure chamber 2660 is fluidicly coupled to the passage 2590 via one or
more passages 2595. During operation of the apparatus 2500, the plug 2655 engages with
5 the throat passage 2650 to fluidicly isolate the fluid passage 2590 from the fluid passage
2600. The pressure chamber 2660 is then pressurized which in turn causes the upper
sealing head 2535, outer sealing mandrel 2545, and expansion cone 2555 to reciprocate
in the axial direction. The axial motion of the expansion cone 2555 in turn expands the
casing 2560 in the radial direction.
10 The load mandrel 2550 is coupled to the lower sealing head 2540. The load
mandrel 2550 preferably comprises an annular member having substantially cylindrical
inner and outer surfaces. The load mandrel 2550 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield country
tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength
15 materials. In a preferred embodiment, the load mandrel 2550 is fabricated from stainless
steel in order to optimally provide high strength, corrosion resistance, and low friction
surfaces.
The load mandrel 2550 may be coupled to the lower sealing head 2540 using any
number of conventional commercially available mechanical couplings such as, for
20 example, oilfield country tubular goods, drillpipe connection, welding, amorphous
bonding, or a standard threaded connection. In a preferred embodiment, the load mandrel
2550 is removably coupled to the lower sealing head 2540 by a standard threaded
connection.
The load mandrel 2550 preferably includes a fluid passage 2600 that is adapted to
25 convey fluidic materials from the fluid passage 2590 to the region outside of the apparatus
2500. In a preferred embodiment, the fluid passage 2600 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at
operating pressures and flow rates ranging, for example, from about 0 to 9,000 psi and 0
to 3,000 gallons/minute (0 to 620.528 bar and 0 to 11 356.24 litres/minute).
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The expansion cone 2555 is coupled to the outer sealing mandrel 2545. The
expansion cone 2555 is also movably coupled to the inner surface of the casing 2560. In
this manner, the upper sealing head 2535, outer sealing mandrel 2545, and the expansion
cone 2555 reciprocate in the axial direction. The reciprocation of the expansion cone
5 2555 causes the casing 2560 to expand in the radial direction.
The expansion cone 2555 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius of the outside
conical surface may range, for example, from about 2 to 34 inches (5.08 to 86.36
centimetres). In a preferred embodiment, the outside radius of the outside conical surface
10 ranges from about 3 to 28 in order to optimally provide radial expansion for the widest
variety of tubular casings. The axial length of the expansion cone 2555 may range, for
example, from about 2 to 8 times the largest outside diameter of the expansion cone 2535.
In a preferred embodiment, the axial length of the expansion cone 2535 ranges from about
3 to 5 times the largest outside diameter of the expansion cone 2535 in order to optimally
15 provide stabilization and centralization of the expansion cone 2535 during the expansion
process. In a particularly preferred embodiment, the maximum outside diameter of the
expansion cone 2555 is between about 95 to 99 % of the inside diameter of the existing
wellbore that the casing 2560 will be joined with. In a preferred embodiment, the angle
of attack of the expansion cone 2555 ranges from about 5 to 30 degrees in order to
20 optimally balance factional forces and radial expansion forces. The optimum angle of
attack of the expansion cone 2535 will vary as a function of the particular operational
features of the expansion operation.
The expansion cone 2555 may be fabricated from any number of conventional
commercially available materials such as, for example, machine tool steel, nitride steel,
25 titanium, tungsten carbide, ceramics or other similar high strength materials. In a
preferred embodiment, the expansion cone 2555 is fabricated from D2 machine tool steel
in order to optimally provide high strength, and resistance to wear and galling. In a
particularly preferred embodiment, the outside surface of the expansion cone 2555 has a
surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
30 high strength and wear resistance.
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The expansion cone 2555 may be coupled to the outside sealing mandrel 2545
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding or a standard threaded connection. In a
5 preferred embodiment, the expansion cone 2555 is coupled to the outside sealing mandrel
2545 using a standard threaded connection in order to optimally provide high strength and
easy replacement of the expansion cone 2555.
The casing 2560 is removably coupled to the slips 2525 and expansion cone 2555.
The casing 2560 preferably comprises a tubular member. The casing 2560 may be
10 fabricated from any number of conventional commercially available materials such as, for
example, slotted tubulars, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
casing 2560 is fabricated from oilfield country tubular goods available from various
foreign and domestic steel mills in order to optimally provide high strength using
15 standardized materials.
In a preferred embodiment, the upper end 2665 of the casing 2560 includes a thin
wall section 2670 and an outer annular sealing member 2675. In a preferred embodiment,
the wall thickness of the thin wall section 2670 is about 50 to 100 % of the regular wall
thickness of the casing 2560. In this manner, the upper end 2665 of the casing 2560 may
20 be easily radially expanded and deformed into intimate contact with the lower end of an
existing section of wellbore casing. In a preferred embodiment, the lower end of the
existing section of casing also includes a thin wall section. In this manner, the radial
expansion of the thin walled section 2670 of casing 2560 into the thin walled section of
the existing wellbore casing results in a wellbore casing having a substantially constant
25 inside diameter.
The annular sealing member 2675 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, epoxy,
rubber, metal, or plastic. In a preferred embodiment, the annular sealing member 2675 is
fabricated from StrataLock epoxy in order to optimally provide compressibility and
30 resistance to wear. The outside diameter of the annular sealing member 2675 preferably
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ranges from about 70 to 95 % of the inside diameter of the lower section of the wellbore
casing that the casing 2560 is joined to. In this manner, after radial expansion, the annular
sealing member 2670 optimally provides a fluidic seal and also preferably optimally
provides sufficient frictional force with the inside surface of the existing section of
5 wellbore casing during the radial expansion of the casing 2560 to support the casing 2560.
In a preferred embodiment, the lower end 2680 of the casing 2560 includes a thin
wall section 2685 and an outer annular sealing member 2690. In a preferred embodiment,
the wall thickness of the thin wall section 2685 is about 50 to 100 % of the regular wall
thickness of the casing 2560. In this manner, the lower end 2680 of the casing 2560 may
10 be easily expanded and deformed. Furthermore, in this manner, an other section of casing
may be easily joined with the lower end 2680 of the casing 2560 using a radial expansion
process. In a preferred embodiment, the upper end of the other section of casing also
includes a thin wall section. In this manner, the radial expansion of the thin walled section
of the upper end of the other casing into the thin walled section 2685 of the lower end
15 2680 of the casing 2560 results in a wellbore casing having a substantially constant inside
diameter.
The annular sealing member 2690 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, rubber, metal,
plastic or epoxy. In a preferred embodiment, the annular sealing member 2690 is
20 fabricated from StrataLock epoxy in order to optimally provide compressibility and
resistance to wear. The outside diameter of the annular sealing member 2690 preferably
ranges from about 70 to 95 % of the inside diameter of the lower section of the existing
wellbore casing that the casing 2560 is joined to. In this manner, after radial expansion,
the annular sealing member 2690 preferably provides a fluidic seal and also preferably
25 provides sufficient frictional force with the inside wall of the wellbore during the radial
expansion of the casing 2560 to support the casing 2560.
During operation, the apparatus 2500 is preferably positioned in a wellbore with
the upper end 2665 of the casing 2560 positioned in an overlapping relationship with the
lower end of an existing wellbore casing. In a particularly preferred embodiment, the thin
30 wall section 2670 of the casing 2560 is positioned in opposing overlapping relation with
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the thin wall section and outer annular sealing member of the lower end of the existing
section of wellbore casing. In this manner, the radial expansion of the casing 2560 will
compress the thin wall sections and annular compressible members of the upper end 2665
of the casing 2560 and the lower end of the existing wellbore casing into intimate contact.
5 During the positioning of the apparatus 2500 in the wellbore, the casing 2560 is supported
by the expansion cone 2555.
After positioning of the apparatus 2500, a first fluidic material is then pumped into
the fluid passage 2565. The first fluidic material may comprise any number of
conventional commercially available materials such as, for example, cement, water, slag-
10 mix, epoxy or drilling mud. In a preferred embodiment, the first fluidic material
comprises a hardenable fluidic sealing material such as, for example, cement, epoxy, or
slag-mix in order to optimally provide a hardenable outer annular body around the
expanded casing 2560.
The first fluidic material may be pumped into the fluid passage 2565 at operating
15 pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000
gallons/minute (0 to 310.264 bar and 0 to 11356.24 litres/minute). In a preferred
embodiment, the first fluidic material is pumped into the fluid passage 2565 at operating
pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 24 1 .3 1 6 bar and 0 to 4542.49 litres/minute) in order to optimally provide operational
20 efficiency.
The first fluidic material pumped into the fluid passage 2565 passes through the
fluid passages 2570, 2575, 2580, 2590, 2600 and then outside of the apparatus 2500. The
first fluidic material then preferably fills the annular region between the outside of the
apparatus 2500 and the interior walls of the wellbore.
25 The plug 2655 is then introduced into the fluid passage 2565. The plug 2655
lodges in the throat passage 2650 and fluidicly isolates and blocks off the fluid passage
2590. In a preferred embodiment, a couple of volumes of a non-hardenable fluidic
material are then pumped into the fluid passage 2565 in order to remove any hardenable
fluidic material contained within and to ensure that none of the fluid passages are blocked.
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A second fluidic material is then pumped into the fluid passage 2565. The second
fluidic material may comprise any number of conventional commercially available
materials such as, for example, water, drilling gases, drilling mud or lubricant. In a
preferred embodiment, the second fluidic material comprises a non-hardenable fluidic
5 material such as, for example, water, drilling mud, or lubricant in order to optimally
provide pressurization of the pressure chamber 2660 and minimize friction.
The second fluidic material may be pumped into the fluid passage 2565 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0
to 4,500 gallons/minute (0 to 3 1 0.264 bar and 0 to 1 7034.35 litres/minute). In a preferred
10 embodiment, the second fluidic material is pumped into the fluid passage 2565 at
operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200
gallons/minute (0 to 241.316 bar and 0 to 4542.49 litres/minute) in order to optimally
provide operational efficiency.
The second fluidic material pumped into the fluid passage 2565 passes through the
15 fluid passages 2570, 2575, 2580, 2590 and into the pressure chambers 2605 of the slips
2525, and into the pressure chamber 2660. Continued pumping of the second fluidic
material pressurizes the pressure chambers 2605 and 2660.
The pressurization of the pressure chambers 2605 causes the slip members 2525
to expand in the radial direction and grip the interior surface of the casing 2560. The
20 casing 2560 is then preferably maintained in a substantially stationary position.
The pressurization of the pressure chamber 2660 causes the upper sealing head
2535, outer sealing mandrel 2545 and expansion cone 2555 to move in an axial direction
relative to the casing 2560. In this manner, the expansion cone 2555 will cause the casing
2560 to expand in the radial direction, beginning with the lower end 2685 of the casing
25 2560.
During the radial expansion process, the casing 2560 is prevented from moving in
an upward direction by the slips 2525. A length of the casing 2560 is then expanded in
the radial direction through the pressurization of the pressure chamber 2660. The length
of the casing 2560 that is expanded during the expansion process will be proportional to
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the stroke length of the upper sealing head 2535, outer sealing mandrel 2545, and
expansion cone 2555.
Upon the completion of a stroke, the operating pressure of the second fluidic
material is reduced and the upper sealing head 2535, outer sealing mandrel 2545, and
5 expansion cone 2555 drop to their rest positions with the casing 2560 supported by the
expansion cone 2555. The position ofthedrillpipe 2505 is preferably adjusted throughout
the radial expansion process in order to maintain the overlapping relationship between the
thin walled sections of the lower end of the existing wellbore casing and the upper end of
the casing 2560. In a preferred embodiment, the stroking of the expansion cone 2555 is
10 then repeated, as necessary, until the thin walled section 2670 of the upper end 2665 of the
casing 2560 is expanded into the thin walled section of the lower end of the existing
wellbore casing. In this manner, a wellbore casing is formed including two adjacent
sections of casing having a substantially constant inside diameter. This process may then
be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet
15 in length having a substantially constant inside diameter.
In a preferred embodiment, during the final stroke of the expansion cone 2555, the
slips 2525 are positioned as close as possible to the thin walled section 2670 of the upper
end 2665 of the casing 2560 in order minimize slippage between the casing 2560 and the
existing wellbore casing at the end of the radial expansion process. Alternatively, or in
20 addition, the outside diameter of the annular sealing member 2675 is selected to ensure
sufficient interference fit with the inside diameter of the lower end of the existing casing
to prevent axial displacement of the casing 2560 during the final stroke. Alternatively, or
inaddition, the outside diameterof the annular sealing member 2690 is selected toprovide
an interference fit with the inside walls of the wellbore at an earlier point in the radial
25 expansion process so as to prevent further axial displacement of the casing 2560. In this
final alternative, the interference fit is preferably selected to permit expansion of the
casing 2560 by pulling the expansion cone 2555 out of the wellbore, without having to
pressurize the pressure chamber 2660.
During the radial expansion process, the pressurized areas of the apparatus 2500
30 are preferably limited to the fluidpassages 2565, 2570, 25 75, 2580, and 2590, the pressure
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chambers 2605 within the slips 2525, and the pressure chamber 2660. No fluid pressure
acts directly on the casing 2560. This permits the use of operating pressures higher than
the casing 2560 could normally withstand.
Once the casing 2560 has been completely expanded off of the expansion cone
5 2555, the remaining portions of the apparatus 2500 are removed from the wellbore. In a
preferred embodiment, the contact pressure between the deformed thin wall sections and
compressible annular members of the lower end of the existing casing and the upper end
2665 of the casing 2560 ranges from about 400 to 10,000 psi (27.58 to 689.476 bar) in
order to optimally support the casing 2560 using the existing wellbore casing.
10 In this manner, the casing 2560 is radially expanded into contact with an existing
section of casing by pressurizing the interior fluid passages 2565, 2570, 2575, 2580, and
2590, the pressure chambers of the slips 2605 and the pressure chamber 2660 of the
apparatus 2500.
In a preferred embodiment, as required, the annular body of hardenable fluidic
15 material is then allowed to cure to form a rigid outer annular body about the expanded
casing 2560. In the case where the casing 2560 is slotted, the cured fluidic material
preferably permeates and envelops the expanded casing 2560. The resulting new section
of wellbore casing includes the expanded casing 2560 and the rigid outer annular body.
The overlapping joint between the pre-existing wellbore casing and the expanded casing
20 2560 includes the deformed thin wail sections and the compressible outer annular bodies.
The inner diameter of the resulting combined wellbore casings is substantially constant.
In this manner, a mono-diameter wellbore casing is formed. This process of expanding
overlapping tubular members having thin wall end portions with compressible annular
bodies into contact can be repeated for the entire length of a wellbore. In this manner, a
25 mono-diameter wellbore casing can be provided for thousands of feet in a subterranean
formation.
In a preferred embodiment, as the expansion cone 2555 nears the upper end 2665
of the casing 2560, the operating pressure of the second fluidic material is reduced in order
to minimize shock to the apparatus 2500. In an alternative embodiment, the apparatus
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2500 includes a shock absorber for absorbing the shock created by the completion of the
radial expansion of the casing 2560.
In a preferred embodiment, the reduced operating pressure of the second fluidic
material ranges from about 1 00 to 1 ,000 psi (6.8947 to 68.947 bar) as the expansion cone
5 2555 nears the end of the casing 2560 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2555. In a preferred embodiment, the
operating pressure of the second fluidic material is reduced during the return stroke of the
apparatus 2500 to the range of about 0 to 500 psi (0 to 34.47 bar) in order minimize the
resistance to the movement of the expansion cone 2555 during the return stroke. In a
10 preferred embodiment, the stroke length of the apparatus 2500 ranges from about 10to45
feet (3.048 to 13.716 metres) in order to optimally provide equipments lengths that can
be easily handled using typical oil well rigging equipment and also minimize the
frequency at which apparatus 2500 must be re-stroked.
In an alternative embodiment, at least a portion of the upper sealing head 2535
15 includes an expansion cone for radially expanding the casing 2560 during operation of the
apparatus 2500 in order to increase the surface area of the casing 2560 acted upon during
the radial expansion process. In this manner, the operating pressures can be reduced.
Alternatively, the apparatus 2500 may be used to join a first section of pipeline to
an existing section of pipeline. Alternatively, the apparatus 2500 may be used to directly
20 line the interior of a wellbore with a casing, without the use of an outer annular layer of
a hardenable material. Alternatively, the apparatus 2500 may be used to expand a tubular
support member in a hole.
Referring now to Figures 19, 1 9a and 19b, another embodiment of an apparatus
2700 for expanding a tubular member will be described. The apparatus 2700 preferably
25 includes a drillpipe 2705, an innerstring adapter 27 1 0, a sealing sleeve 27 1 5, a first inner
sealing mandrel 2720, a first upper sealing head 2725, a first lower sealing head 2730, a
first outer sealing mandrel 2735, a second inner sealing mandrel 2740, a second upper
sealing head 2745, a second lower sealing head 2750, a second outer sealing mandrel
2755, a load mandrel 2760, an expansion cone 2765, a mandrel launcher 2770, a
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mechanical slip body 2775, mechanical slips 2780, drag blocks 2785, casing 2790, and
fluid passages 2795, 2800, 2805, 2810, 2815, 2820, 2825, and 2830.
The drillpipe 2705 is coupled to the innerstring adapter 2710. During operation
of the apparatus 2700, the drillpipe 2705 supports the apparatus 2700. The drillpipe 2705
5 preferably comprises a substantially hollow tubular member or members. The drillpipe
2705 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel, or other similar high strength materials. In a preferred embodiment, the
drillpipe 2705 is fabricated from coiled tubing in order to facilitate the placement of the
10 apparatus 2700 in non-vertical wellbores. The drillpipe 2705 may be coupled to the
innerstring adapter 2710 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, or a standard threaded connection. In a preferred
embodiment, the drillpipe 2705 is removably coupled to the innerstring adapter 2710 by
15 a drillpipe connection in order to optimally provide high strength and easy disassembly.
The drillpipe 2705 preferably includes a fluid passage 2795 that is adapted to
convey fluidic materials from a surface location into the fluid passage 2800. In a preferred
embodiment, the fluid passage 2795 is adapted to convey fluidic materials such as, for
example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow
20 rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.528 bar
and 0 to 1 1356.24 litres/minute).
The innerstring adapter 2710 is coupled to the drill string 2705 and the sealing
sleeve 2715. The innerstring adapter 2710 preferably comprises a substantially hollow
tubular member or members. The innerstring adapter 2710 may be fabricated from any
25 number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the innerstring adapter 271 0 is fabricated
from stainless steel in order to optimally provide high strength, corrosion resistance, and
low friction surfaces.
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The innerstring adapter 2710 may be coupled to the drill string 2705 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty threaded
connection, or a standard threaded connection. In a preferred embodiment, the innerstring
5 adapter 2710 is removably coupled to the drill pipe 2705 by a standard threaded
connection in order to optimally provide high strength and easy disassembly. The
innerstring adapter 2710 may be coupled to the sealing sleeve 2715 using any number of
conventional commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch
10 type threaded connection or a standard threaded connection. In a preferred embodiment,
the innerstring adapter 27 1 0 is removably coupled to the sealing sleeve 27 1 5 by a standard
threaded connection.
The innerstring adapter 2710 preferably includes a fluid passage 2800 that is
adapted to convey fluidic materials from the fluid passage 2795 into the fluid passage
15 2805. In a preferred embodiment, the fluid passage 2800 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356,24 litres/minute).
The sealing sleeve 2715 is coupled to the innerstring adapter 2710 and the first
20 inner sealing mandrel 2720. The sealing sleeve 27 15 preferably comprises a substantially
hollow tubular member or members. The sealing sleeve 2715 may be fabricated from any
number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the sealing sleeve 271 5 is fabricated from
25 stainless steel in order to optimally provide high strength, corrosion resistance, and low
friction surfaces.
The sealing sleeve 27 1 5 may be coupled to the innerstring adapter 27 1 0 using any
number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
30 connection, welding, amorphous bonding, or a standard threaded connection. In a
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preferred embodiment, the sealing sleeve 2715 is removably coupled to the innerstring
adapter 2710 by a standard threaded connector. The sealing sleeve 27 1 5 may be coupled
to the first inner sealing mandrel 2720 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection, oilfield country
5 tubular goods specialty type threaded connection, welding, amorphous bonding or a
standard threaded connection. In a preferred embodiment, the sealing sleeve 2715 is
removably coupled to the inner sealing mandrel 2720 by a standard threaded connection.
The sealing sleeve 2715 preferably includes a fluid passage 2802 that is adapted
to convey fluidic materials from the fluid passage 2800 into the fluid passage 2805. In a
10 preferred embodiment, the fluid passage 2802 is adapted to convey fluidic materials such
as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures
and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356.24 litres/minute).
The first inner sealing mandrel 2720 is coupled to the sealing sleeve 271 5 and the
15 first lower sealing head 2730. The first inner sealing mandrel 2720 preferably comprises
a substantially hollow tubular member or members. The first inner sealing mandrel 2720
maybe fabricated from any number of conventional commercially available materials such
as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the first inner sealing
20 mandrel 2720 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The first inner sealing mandrel 2720 may be coupled to the sealing sleeve 2715
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection oilfield country tubular goods specialty threaded
25 connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the first inner sealing mandrel 2720 is removably coupled to the
sealing sleeve 271 5 by a standard threaded connection. The first inner sealing mandrel
2720 may be coupled to the first lower sealing head 2730 using any number of
conventional commercially available mechanical couplings such as, for example, drillpipe
30 connection, oilfield country tubular goods specialty type threaded connection, welding,
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amorphous bonding, or a standard threaded connection. In a preferred embodiment, the
first inner sealing mandrel 2720 is removably coupled to the first lower sealing head 2730
by a standard threaded connection.
The first inner sealing mandrel 2720 preferably includes a fluid passage 2805 that
5 is adapted to convey fluidic materials from the fluid passage 2802 into the fluid passage
2810. In a preferred embodiment, the fluid passage 2805 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
10 The first upper sealing head 2725 is coupled to the first outer sealing mandrel
2735, the second upper sealing head 2745, the second outer sealing mandrel 2755, and the
expansion cone 2765. The first upper sealing head 2725 is also movably coupled to the
outer surface of the first inner sealing mandrel 2720 and the inner surface of the casing
2790. In this manner, the first upper sealing head 2725 reciprocates in the axial direction.
15 The radial clearance between the inner cylindrical surface of the first upper sealing head
2725 and the outer surface of the first inner sealing mandrel 2720 may range, for example,
from about 0.0025 to 0,05 inches (0.00635 to 0.127 centimetres). In a preferred
embodiment, the radial clearance between the inner cylindrical surface of the first upper
sealing head 2725 and the outer surface of the first inner sealing mandrel 2720 ranges
20 from about 0.005 to 0.125 inches (0.0127 to 0.3175 centimetres) in order to optimally
provide minimal radial clearance. The radial clearance between the outer cylindrical
surface of the first upper sealing head 2725 and the inner surface of the casing 2790 may
range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In
a preferred embodiment, the radial clearance between the outer cylindrical surface of the
25 first upper sealing head 2725 and the inner surface of the casing 2790 ranges from about
0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in order to optimally provide
stabilization for the expansion cone 2765 during the expansion process.
The first upper sealing head 2725 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The first upper sealing head 2725 may
30 be fabricated from any number of conventional commercially available materials such as,
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for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the first upper sealing
head 2725 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance and low friction surfaces. The inner surface of the first upper sealing
5 head 2725 preferably includes one or more annular sealing members 2835 for sealing the
interface between the first upper sealing head 2725 and the first inner sealing mandrel
2720. The sealing members 2835 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing members
10 2835 comprise polypak seals available from Parker Seals in order to optimally provide
sealing for long axial strokes.
In a preferred embodiment, the first upper sealing head 2725 includes a shoulder
2840 for supporting the first upper sealing head 2725 on the first lower sealing head 2730.
1 5 The first upper sealing head 2725 may be coupled to the first outer sealing mandrel
2735 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty
threaded connection, welding, amorphous bonding or a standard threaded connection. In
a preferred embodiment, the first upper sealing head 2725 is removably coupled to the first
20 outer sealing mandrel 2735 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the first upper sealing head 2725 and the
first outer sealing mandrel 2735 includes one or more sealing members 2845 for fluidicly
sealing the interface between the first upper sealing head 2725 and the first outer sealing
mandrel 2735. The sealing members 2845 may comprise any number of conventional
25 commercially available sealing members such as, for example, o-rings, polypak seals or
metal spring energized seals. In a preferred embodiment, the sealing members 2845
comprise polypak seals available from Parker Seals in order to optimally provide sealing
for long axial strokes.
The first lower sealing head 2730 is coupled to the first inner sealing mandrel 2720
30 and the second inner sealing mandrel 2740. The first lower sealing head 2730 is also
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movably coupled to the inner surface of the first outer sealing mandrel 2735. In this
manner, the first upper sealing head 2725 and first outer sealing mandrel 2735 reciprocate
in the axial direction. The radial clearance between the outer surface of the first lower
sealing head 2730 and the inner surface of the first outer sealing mandrel 273 5 may range,
5 for example, from about 0.0025 to 0.05 inches (0.00635 to 0.127 centimetres). In a
preferred embodiment, the radial clearance between the outer surface of the first lower
sealing head 2730 and the inner surface of the first outer sealing mandrel 2735 ranges
from about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres) in order to optimally
provide minimal radial clearance.
10 The first lower sealing head 2730 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The first lower sealing head 2730 may
be fabricated from any number of conventional commercially available materials such as,
for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the first lower sealing
15 head 2730 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the first lower sealing
head 2730 preferably includes one or more annular sealing members 2850 for sealing the
interface between the first lower sealing head 2730 and the first outer sealing mandrel
2735. The sealing members 2850 may comprise any number of conventional
20 commercially available annular sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing members
2850 comprise polypak seals available from Parker Seals in order to optimally provide
sealing for long axial strokes.
The first lower sealing head 2730 maybe coupled to the first inner sealing mandrel
25 2720 using any number of conventional commercially available mechanical couplings
such as, for example, oilfield country tubular goods specialty threaded connections,
welding, amorphous bonding, or standard threaded connection. In a preferred
embodiment, the first lower sealing head 2730 is removably coupled to the first inner
sealing mandrel 2720 by a standard threaded connection. In a preferred embodiment, the
30 mechanical coupling between the first lower sealing head 2730 and the first inner sealing
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mandrel 2720 includes one or more sealing members 2855 for fluidicly sealing the
interface between the first lower sealing head 2730 and the first inner sealing mandrel
2720. The sealing members 2855 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak seals or
5 metal spring energized seals. In a preferred embodiment, the sealing members 2855
comprise polypak seals available from Parker Seals in order to optimally provide sealing
for long axial strokes.
The first lower sealing head 2730 may be coupled to the second inner sealing
mandrel 2740 using any number of conventional commercially available mechanical
10 couplings such as, for example, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the lower sealing head 2730 is removably coupled to the second
inner sealing mandrel 2740 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the first lower sealing head 2730 and the
15 second inner sealing mandrel 2740 includes one or more sealing members 2860 for
fluidicly sealing the interface between the first lower sealing head 2730 and the second
inner sealing mandrel 2740. The sealing members 2860 may comprise any number of
conventional commercially available sealing members such as, for example, o-rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the sealing
20 members 2860 comprise polypak seals available from Parker Seals in order to optimally
provide sealing for long axial strokes.
The first outer sealing mandrel 2735 is coupled to the first upper sealing head
2725, the second upper sealing head 2745, the second outer sealing mandrel 2755, and the
expansion cone 2765. The first outer sealing mandrel 2735 is also movably coupled to the
25 inner surface of the casing 2790 and the outer surface of the first lower sealing head 2730.
In this manner, the first upper sealing head 2725, first outer sealing mandrel 2735, second
upper sealing head 2745, second outer sealing mandrel 2755, and the expansion cone 2765
reciprocate in the axial direction. The radial clearance between the outer surface of the
first outer sealing mandrel 2735 and the inner surface of the casing 2790 may range, for
30 example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In a preferred
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embodiment, the radial clearance between the outer surface of the first outer sealing
mandrel 2735 and the inner surface of the casing 2790 ranges from about 0.025 to 0. 125
inches (0.0635 to 0.3175 centimetres) in order to optimally provide stabilization for the
expansion cone 2765 during the expansion process. The radial clearance between the
5 inner surface of the first outer sealing mandrel 273 5 and the outer surface of the first lower
sealing head 2730 may range, for example, from about 0.0025 to 0.05 inches (0.00635 to
0. 127 centimetres). In a preferred embodiment, the radial clearance between the inner
surface of the first outer sealing mandrel 2735 and the outer surface of the first lower
sealing head 2730 ranges from about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres)
10 in order to optimally provide minimal radial clearance.
The outer sealing mandrel 1935 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The first outer sealing mandrel 2735
may be fabricated from any number of conventional commercially available materials such
as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
1 5 or other similar high strength materials. In a preferred embodiment, the first outer sealing
mandrel 2735 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The first outer sealing mandrel 2735 may be coupled to the first upper sealing head
2725 using any number of conventional commercially available mechanical couplings
20 such as, for example, oilfield country tubular goods, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the first outer sealing mandrel
2735 is removably coupled to the first upper sealing head 2725 by a standard threaded
connection. The first outer sealing mandrel 2735 may be coupled to the second upper
sealing head 2745 using any number of conventional commercially available mechanical
25 couplings such as, for example, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the first outer sealing mandrel 2735 is removably coupled to the
second upper sealing head 2745 by a standard threaded connection.
The second inner sealing mandrel 2740 is coupled to the first lower sealing head
30 2730 and the second lower sealing head 2750. The second inner sealing mandrel 2740
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preferably comprises a substantially hollow tubular member or members. The second
inner sealing mandrel 2740 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength materials. In a
5 preferred embodiment, the second inner sealing mandrel 2740 is fabricated from stainless
steel in order to optimally provide high strength, corrosion resistance, and low friction
surfaces.
The second inner sealing mandrel 2740 may be coupled to the first lower sealing
head 2730 using any number of conventional commercially available mechanical
10 couplings such as, for example, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the second inner sealing mandrel 2740 is removably coupled to the
first lower sealing head 2 740 by a standard threaded connection. The mechanical coupling
between the second inner sealing mandrel 2740 and the first lower sealing head 2730
15 preferably includes sealing members 2860.
The second inner sealing mandrel 2740 may be coupled to the second lower sealing
head 2750 using any number of conventional commercially available mechanical
couplings such as, for example, oilfield country tubular goods specialty threaded
connection, welding, amorphous bonding, or a standard threaded connection. In a
20 preferred embodiment, the second inner sealing mandrel 2720 is removably coupled to the
second lower sealing head 2750 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the second inner sealing mandrel 2740 and
the second lower sealing head 2750 includes one or more sealing members 2865. The
sealing members 2865 may comprise any number of conventional commercially available
25 seals such as, for example, o-rings, polypak seals or metal spring energized seals. In a
preferred embodiment, the sealing members 2865 comprise polypak seals available from
Parker Seals.
The second inner sealing mandrel 2740 preferably includes a fluid passage 28 10
that is adapted to convey fluidic materials from the fluid passage 2805 into the fluid
30 passage 2815. In a preferred embodiment, the fluid passage 2810 is adapted to convey
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fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The second upper sealing head 2745 is coupled to the first upper sealing head
5 2725, the first outer sealing mandrel 2735, the second outer sealing mandrel 2755, and the
expansion cone 2765. The second upper sealing head 2745 is also movably coupled to the
outer surface of the second inner sealing mandrel 2740 and the inner surface of the casing
2790. In this manner, the second upper sealing head 2745 reciprocates in the axial
direction. The radial clearance between the inner cylindrical surface of the second upper
10 sealing head 2745 and the outer surface of the second inner sealing mandrel 2740 may
range, for example, from about 0.0025 to 0.05 inches (0.00635 to 0. 127 centimetres). In
a preferred embodiment, the radial clearance between the inner cylindrical surface of the
second upper sealing head 2745 and the outer surface of the second inner sealing mandrel
2740 ranges from about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres) in order to
15 optimally provide minimal radial clearance. The radial clearance between the outer
cylindrical surface of the second upper sealing head 2745 and the inner surface of the
casing 2790 may range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525
centimetres). In a preferred embodiment, the radial clearance between the outer
cylindrical surface of the second upper sealing head 2745 and the inner surface of the
20 casing 2790 ranges from about 0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in
order to optimally provide stabilization for the expansion cone 2765 during the expansion
process.
The second upper sealing head 2745 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The second upper sealing head
25 2745 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
second upper sealing head 2745 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces. The inner surface
30 of the second upper sealing head 2745 preferably includes one or more annular sealing
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members 2870 for sealing the interface between the second upper sealing head 2745 and
the second inner sealing mandrel 2740. The sealing members 2870 may comprise any
number of conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a preferred
5 embodiment, the sealing members 2870 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for long axial strokes.
In a preferred embodiment, the second upper sealing head 2745 includes a shoulder
2875 for supporting the second upper sealing head 2745 on the second lower sealing head
2750.
10 The second upper sealing head 2745 may be coupled to the first outer sealing
mandrel 2735 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, ratchet-latch type threaded connection, or a standard
threaded connection. In a preferred embodiment, the second upper sealing head 2745 is
15 removably coupled to the first outer sealing mandrel 2735 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the second
upper sealing head 2745 and the first outer sealing mandrel 2735 includes one or more
sealing members 2880 for fluidicly sealing the interface between the second upper sealing
head 2745 and the first outer sealing mandrel 2735. The sealing members 2880 may
20 comprise any number of conventional commercially available sealing members such as,
for example, o-rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2880 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial stroke.
The second upper sealing head 2745 may be coupled to the second outer sealing
25 mandrel 2755 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, or a standard threaded connection. In a preferred
embodiment, the second upper sealing head 2745 is removably coupled to the second
outer sealing mandrel 2755 by a standard threaded connection. In a preferred
30 embodiment, the mechanical coupling between the second upper sealing head 2745 and
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the second outer sealing mandrel 2755 includes one or more sealing members 2885 for
fluidicly sealing the interface between the second upper sealing head 2745 and the second
outer sealing mandrel 2755. The sealing members 2885 may comprise any number of
conventional commercially available sealing members such as, for example, o-rings,
5 polypak seals or metal spring energized seals. In a preferred embodiment, the sealing
members 2885 comprise polypak seals available from Parker Seals in order to optimally
provide sealing for long axial strokes.
The second lower sealing head 2750 is coupled to the second inner sealing mandrel
2740 and the load mandrel 2760. The second lower sealing head 2750 is also movably
10 coupled to the inner surface of the second outer sealing mandrel 2755. In this manner, the
first upper sealing head 2725, the first outer sealing mandrel 2735, second upper sealing
head 2745, second outer sealing mandrel 2755, and the expansion cone 2765 reciprocate
in the axial direction. The radial clearance between the outer surface of the second lower
sealing head 2750 and the inner surface of the second outer sealing mandrel 2755 may
16 range, for example, from about 0.0025 to 0.05 inches (0.00635 to 0. 127 centimetres). In
a preferred embodiment, the radial clearance between the outer surface of the second
lower sealing head 2750 and the inner surface of the second outer sealing mandrel 2755
ranges from about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres) in order to optimally
provide minimal radial clearance.
20 The second lower sealing head 2750 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The second lower sealing head
2750 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
25 second lower sealing head 2750 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces. The outer surface
of the second lower sealing head 2750 preferably includes one or more annular sealing
members 2890 for sealing the interface between the second lower sealing head 2750 and
the second outer sealing mandrel 2755. The sealing members 2890 may comprise any
30 number of conventional commercially available annular sealing members such as, for
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example, o-rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2890 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for long axial strokes.
The second lower sealing head 2750 may be coupled to the second inner sealing
5 mandrel 2740 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, ratchet-latch type threaded connection, or a standard
threaded connection. In a preferred embodiment, the second lower sealing head 2750 is
removably coupled to the second inner sealing mandrel 2740 by a standard threaded
10 connection. In a preferred embodiment, the mechanical coupling between the second
lower sealing head 2750 and the second inner sealing mandrel 2740 includes one or more
sealing members 2895 for fluidicly sealing the interface between the second sealing head
2750and the second sealing mandrel 2740. The sealing members 2895 may comprise any
number of conventional commercially available sealing members such as, for example,
16 o-rings, polypak seals or metal spring energized seals. In a preferred embodiment, the
sealing members 2895 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
The second lower sealing head 2750 may be coupled to the load mandrel 2760
using any number of conventional commercially available mechanical couplings such as,
20 for example, drillpipe connection, oilfield tubular goods specialty threaded connection,
ratchet-latch type threaded connection, or a standard threaded connection. In a preferred
embodiment, the second lower sealing head 2750 is removably coupled to the load
mandrel 2760 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the second lower sealing head 2750 and the load mandrel
25 2760 includes one or more sealing members 2900 for fluidicly sealing the interface
between the second lower sealing head 2750 and the load mandrel 2760. The sealing
members 2900 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals or metal spring energized seals. In
a preferred embodiment, the sealing members 2900 comprise polypak seals available from
30 Parker Seals in order to optimally provide sealing for long axial strokes.
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In a preferred embodiment, the second lower sealing head 2750 includes a throat
passage 2905 fluidicly coupled between the fluid passages 2810 and 2815. The throat
passage 2905 is preferably of reduced size and is adapted to receive and engage with a
plug 2910, or other similar device. In this manner, the fluid passage 2810 is fluidicly
5 isolated from the fluid passage 2815. In this manner, the pressure chambers 2915 and
2920 are pressurized. The use of a plurality of pressure chambers in the apparatus 2700
permits the effective driving force to be multiplied. While illustrated using a pair of
pressure chambers, 29 1 5 and 2920, the apparatus 2700 may be further modified to employ
additional pressure chambers.
10 The second outer sealing mandrel 2755 is coupled to the first upper sealing head
2725, the first outer sealing mandrel 2735, the second upper sealing head 2745, and the
expansion cone 2765. The second outer sealing mandrel 2755 is also movably coupled
to the inner surface of the casing 2790 and the outer surface of the second lower sealing
head 2750. In this manner, the first upper sealing head 2725, first outer sealing mandrel
15 2735, second upper sealing head 2745, second outer sealing mandrel 2755, and the
expansion cone 2765 reciprocate in the axial direction.
The radial clearance between the outer surface of the second outer sealing mandrel
2755 and the inner surface of the casing 2790 may range, for example, from about 0.025
to 0.375 inches (0.0635 to 0.9525 centimetres). In a preferred embodiment, the radial
20 clearance between the outer surface of the second outer sealing mandrel 2755 and the
inner surface of the casing 2790 ranges from about 0.025 to 0.125 inches (0.0635 to
0.3175 centimetres) in order to optimally provide stabilization for the expansion cone
2765 during the expansion process. The radial clearance between the inner surface of the
second outer sealing mandrel 2755 and the outer surface of the second lower sealing head
25 2750 may range, for example, from about 0.0025 to 0.05 inches (0.00635 to 0.127
centimetres). In a preferred embodiment, the radial clearance between the inner surface
of the second outer sealing mandrel 2755 and the outer surface of the second lower sealing
head 2750 ranges from about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres) in order
to optimally provide minimal radial clearance.
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The second outer sealing mandrel 2755 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The second outer sealing
mandrel 2755 maybe fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
5 stainless steel or other similar high strength materials. In a preferred embodiment, the
second outer sealing mandrel 2755 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces.
The second outer sealing mandrel 2755 may be coupled to the second upper sealing
head 2745 using any number of conventional commercially available mechanical
10 couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, ratchet-latch type threaded connection or a standard
threaded connection. In a preferred embodiment, the second outer sealing mandrel 2755
is removably coupled to the second upper sealing head 2745 by a standard threaded
connection. The second outer sealing mandrel 2755 may be coupled to the expansion cone
15 2765 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty type
threaded connection, ratchet-latch type threaded connection, or a standard threaded
connection. In a preferred embodiment, the second outer sealing mandrel 2755 is
removably coupled to the expansion cone 2765 by a standard threaded connection.
20 The load mandrel 2760 is coupled to the second lower sealing head 2750 and the
mechanical slip body 2755. The load mandrel 2760 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The load mandrel 2760
maybe fabricated from any number of conventional commercially available materials such
as, for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
25 or other similar high strength materials. In a preferred embodiment, the load mandrel
2760 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The load mandrel 2760 may be coupled to the second lower sealing head 2750
using any number of conventional commercially available mechanical couplings such as,
30 for example, drillpipe connection, oilfield country tubular goods specialty type threaded
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connection, ratchet-latch type threaded connection, or a standard threaded connection. In
a preferred embodiment, the load mandrel 2760 is removably coupled to the second lower
sealing head 2750 by a standard threaded connection. The load mandrel 2760 may be
coupled to the mechanical slip body 2775 using any number of conventional commercially
5 available mechanical couplings such as, for example, drillpipe connection, oilfield country
tubular goods specialty type threaded connection, ratchet-latch type threaded connection
or a standard threaded connection. In a preferred embodiment, the load mandrel 2760 is
removably coupled to the mechanical slip body 2775 by a standard threaded connection.
The load mandrel 2760 preferably includes a fluid passage 28 1 5 that is adapted to
10 convey fluidic materials from the fluid passage 2810 to the fluid passage 2820. In a
preferred embodiment, the fluid passage 28 1 5 is adapted to convey fluidic materials such
as, for example, cement, epoxy, water, drilling mud or lubricants at operating pressures
and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356,24 litres/minute).
15 The expansion cone 2765 is coupled to the second outer sealing mandrel 2755.
The expansion cone 2765 is also movably coupled to the inner surface of the casing 2790.
In this manner, the first upper sealing head 2725, first outer sealing mandrel 2735 , second
upper sealing head 2745, second outer sealing mandrel 275 5, and the expansion cone 2765
reciprocate in the axial direction. The reciprocation of the expansion cone 2765 causes
20 the casing 2790 to expand in the radial direction.
The expansion cone 2765 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius of the outside
conical surface may range, for example, from about 2 to 34 inches (5.08 to 86.36
centimetres). In a preferred embodiment, the outside radius of the outside conical surface
25 ranges from about 3 to 28 inches (7.62 to 7 1 . 1 2 centimetres) in order to optimally provide
expansion cone dimensions that accommodate the typical range of casings. The axial
length of the expansion cone 2765 may range, for example, from about 2 to 8 times the
largest outer diameter of the expansion cone 2765. In a preferred embodiment, the axial
length of the expansion cone 2765 ranges from about 3 to 5 times the largest outer
30 diameter of the expansion cone 2765 in order to optimally provide stabilization and
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centralization of the expansion cone 2765. In a preferred embodiment, the angle of attack
of the expansion cone 2765 ranges from about 5 to 30 degrees in order to optimally
balance frictional forces and radial expansion forces.
The expansion cone 2765 may be fabricated from any number of conventional
5 commercially available materials such as, for example, machine tool steel, nitride steel,
titanium, tungsten carbide, ceramics or other similar high strength materials. In a
preferred embodiment, the expansion cone 2765 is fabricated from D2 machine tool steel
in order to optimally provide high strength and resistance to corrosion and galling. In a
particularly preferred embodiment, the outside surface of the expansion cone 2765 has a
10 surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength and resistance to wear and galling.
The expansion cone 2765 may be coupled to the second outside sealing mandrel
2765 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty type
15 threaded connection, ratchet-latch type threaded connection or a standard threaded
connection. In a preferred embodiment, the expansion cone 2765 is coupled to the second
outside sealing mandrel 2765 using a standard threaded connection in order to optimally
provide high strength and easy replacement of the expansion cone 2765.
The mandrel launcher 2770 is coupled to the casing 2790. The mandrel launcher
20 2770 comprises a tubular section of casing having a reduced wall thickness compared to
the casing 2790. In a preferred embodiment, the wall thickness of the mandrel launcher
2770 is about 50 to 100 % of the wall thickness of the casing 2790. The wall thickness
of the mandrel launcher 2770 may range , for example, from about 0.15 to 1.5 inches
(0.38 1 to 3.8 1 centimetres). In a preferred embodiment, the wall thickness of the mandrel
25 launcher 2770 ranges from about 0.25 to 0.75 inches (0.635 to 1 .905 centimetres). In this
manner, the initiation of the radial expansion of the casing 2790 is facilitated, the
placement of the apparatus 2700 within a wellbore casing and wellbore is facilitated, and
the mandrel launcher 2770 has a burst strength approximately equal to that of the casing
2790.
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The mandrel launcher 2770 may be coupled to the casing 2790 using any number
of conventional mechanical couplings such as, for example, a standard threaded
connection. The mandrel launcher 2770 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield country
5 tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high strength
materials. In a preferred embodiment, the mandrel launcher 2770 is fabricated from
oilfield country tubular goods of higher strength than that of the casing 2790 but with a
reduced wall thickness in order to optimally provide a small compact tubular container
having a burst strength approximately equal to that of the casing 2790.
10 The mechanical slip body 2775 is coupled to the load mandrel 2760, the
mechanical slips 2780, and the drag blocks 2785. The mechanical slip body 2775
preferably comprises a tubular member having an inner passage 2820 fluidicly coupled
to the passage 2815. In this manner, fluidic materials may be conveyed from the passage
2820 to a region outside of the apparatus 2700.
15 The mechanical slip body 2775 may be coupled to the load mandrel 2760 using any
number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 2775 is removably coupled to the load mandrel 2760 using a
standard threaded connection in order to optimally provide high strength and easy
disassembly. The mechanical slip body 2775 may be coupled to the mechanical slips 2780
20 using any number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 2755 is removably coupled to the mechanical slips 2780 using
threaded connections and sliding steel retainer rings in order to optimally provide a high
strength attachment. The mechanical slip body 2755 may be coupled to the drag blocks
2785 using any number of conventional mechanical couplings. In a preferred
2 5 embodiment, the mechanical slip body 2775 is removably coupled to the drag blocks 2785
using threaded connections and sliding steel retainer rings in order to optimally provide
a high strength attachment.
The mechanical slip body 2775 preferably includes a fluid passage 2820 that is
adapted to convey fluidic materials from the fluid passage 281 5 to the region outside of
30 the apparatus 2700. In a preferred embodiment, the fluid passage 2820 is adapted to
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convey fluidic materials such as, for example, cement, epoxy, water, drilling mud or
lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0
to 3,000 gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The mechanical slips 2780 are coupled to the outside surface of the mechanical slip
5 body 2775. During operation of the apparatus 2700, the mechanical slips 2780 prevent
upward movement of the casing 2790 and mandrel launcher 2770. In this manner, during
the axial reciprocation of the expansion cone 2765, the casing 2790 and mandrel launcher
2770 are maintained in a substantially stationary position. In this manner, the mandrel
launcher 2765 and casing 2790 and mandrel launcher 2770 are expanded in the radial
10 direction by the axial movement of the expansion cone 2765.
The mechanical slips 2780 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer tungsten
carbide mechanical slips, RTTS packer wicker type mechanical slips or Model 3L
retrievable bridge plug tungsten carbide upper mechanical slips. In a preferred
15 embodiment, the mechanical slips 2780 comprise RTTS packer tungsten carbide
mechanical slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 2790 and mandrel launcher 2770 during the
expansion process.
The drag blocks 2785 are coupled to the outside surface of the mechanical slip
20 body 2775 . During operation of the apparatus 2700, the drag blocks 2785 prevent upward
movement of the casing 2790 and mandrel launcher 2770. In this manner, during the axial
reciprocation of the expansion cone 2765, the casing 2790 and mandrel launcher 2770 are
maintained in a substantially stationary position. In this manner, the mandrel launcher
2770 and casing 2790 are expanded in the radial direction by the axial movement of the
25 expansion cone 2765.
The drag blocks 2785 may comprise any number of conventional commercially
available mechanical slips such as, for example, RTTS packer mechanical drag blocks or
Model 3L retrievable bridge plug drag blocks. In a preferred embodiment, the drag blocks
2785 comprise RTTS packer mechanical drag blocks available from Halliburton Energy
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Services in order to optimally provide resistance to axial movement of the casing 2790 and
mandrel launcher 2770 during the expansion process.
The casing 2790 is coupled to the mandrel launcher 2770. The casing 2790 is
further removably coupled to the mechanical slips 2780 and drag blocks 2785. The casing
5 2790 preferably comprises a tubular member. The casing 2790 may be fabricated from
any number of conventional commercially available materials such as, for example, slotted
tubulars, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel or
other similar high strength materials. In a preferred embodiment, the casing 2790 is
fabricated from oilfield country tubular goods available from various foreign and domestic
10 steel mills in order to optimally provide high strength using standardized materials. In
a preferred embodiment, the upper end of the casing 2790 includes one or more sealing
members positioned about the exterior of the casing 2790.
During operation, the apparatus 2700 is positioned in a wellbore with the upper end
of the casing 2790 positioned in an overlapping relationship within an existing wellbore
15 casing. In order minimize surge pressures within the borehole during placement of the
apparatus 2700, the fluid passage 2795 is preferably provided with one or more pressure
relief passages. During the placement of the apparatus 2700 in the wellbore, the casing
2790 is supported by the expansion cone 2765.
After positioning of the apparatus 2700 within the bore hole in an overlapping
20 relationship with an existing section of wellbore casing, a first fluidic material is pumped
into the fluid passage 2795 from a surface location. The first fluidic material is conveyed
from the fluid passage 2795 to the fluid passages 2800, 2802, 2805, 2810, 281 5, and 2820.
The first fluidic material will then exit the apparatus 2700 and fill the annular region
between the outside of the apparatus 2700 and the interior walls of the bore hole.
25 The first fluidic material may comprise any number of conventional commercially
available materials such as, for example, epoxy, drilling mud, slag mix, water or cement
In a preferred embodiment, the first fluidic material comprises a hardenable fluidic sealing
material such as, for example, slag mix, epoxy, or cement. In this manner, a wellbore
casing having an outer annular layer of a hardenable material may be formed.
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The first fluidic material may be pumped into the apparatus 2700 at operating
pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 3,000
gallons/minute (0 to 310.264 bar, and 0 to 11356.24 litres/minute). In a preferred
embodiment, the first fluidic material is pumped into the apparatus 2700 at operating
5 pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 241 .3 16 bar and 0 to 4542.49 litres/minute) in order to optimally provide operational
efficiency.
At a predetermined point in the injection of the first fluidic material such as, for
example, after the annular region outside of the apparatus 2700 has been filled to a
10 predetermined level, a plug 2910, dart, or other similar device is introduced into the first
fluidic material. The plug 2910 lodges in the throat passage 2905 thereby fluidicly
isolating the fluid passage 2810 from the fluid passage 2815.
After placement of the plug 2910 in the throat passage 2905, a second fluidic
material is pumped into the fluid passage 2795 in order to pressurize the pressure
15 chambers 2915 and 2920. The second fluidic material may comprise any number of
conventional commercially available materials such as, for example, water, drilling gases,
drilling mud or lubricants. In a preferred embodiment, the second fluidic material
comprises a non-hardenable fluidic material such as, for example, water, drilling mud or
lubricant. The use of lubricant optimally provides lubrication of the moving parts of the
20 apparatus 2700,
The second fluidic material may be pumped into the apparatus 2700 at operating
pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500
gallons/minute (0 to 310.264 bar and 0 to 17034.35 litres/minute). In a preferred
embodiment, the second fluidic material is pumped into the apparatus 2700 at operating
25 pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 241 .3 16 bar and 0 to 4542.49 litres/minute) in order to optimally provide operational
efficiency.
The pressurization of the pressure chambers 29 1 5 and 2920 cause the upper sealing
heads, 2725 and 2745, outer sealing mandrels, 2735 and 2755, and expansion cone 2765
30 to move in an axial direction. As the expansion cone 2765 moves in the axial direction,
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the expansion cone 2765 pulls the mandrel launcher 2770, casing 2790, and drag blocks
2785 along, which sets the mechanical slips 2780 and stops further axial movement of the
mandrel launcher 2770 and casing 2790. In this manner, the axial movement of the
expansion cone 2765 radially expands the mandrel launcher 2770 and casing 2790.
5 Once the upper sealing heads, 2725 and 2745, outer sealing mandrels, 2735 and
2755, and expansion cone 2765 complete an axial stroke, the operating pressure of the
second fluidic material is reduced and the drill string 2705 is raised. This causes the inner
sealing mandrels, 2720 and 2740, lower sealing heads, 2730 and 2750, load mandrel 2760,
and mechanical slip body 2755 to move upward. This unsets the mechanical slips 2780
10 and permits the mechanical slips 2780 and drag blocks 2785 to be moved upward within
the mandrel launcher 2770 and casing 2790. When the lower sealing heads, 2730 and
2750, contact the upper sealing heads, 2725 and 2745, the second fluidic material is again
pressurized and the radial expansion process continues. In this manner, the mandrel
launcher 2770 and casing 2790 are radially expanded through repeated axial strokes of the
15 upper sealing heads, 2725 and 2745, outer sealing mandrels, 2735 and 2755, and
expansion cone 2765. Throughout the radial expansion process, the upper end of the
casing 2790 is preferably maintained in an overlapping relation with an existing section
of wellbore casing.
At the end of the radial expansion process, the upper end of the casing 2790 is
20 expanded into intimate contact with the inside surface of the lower end of the existing
wellbore casing. In a preferred embodiment, the sealing members provided at the upper
end of the casing 2790 provide a fluidic seal between the outside surface of the upper end
of the casing 2790 and the inside surface of the lower end of the existing wellbore casing.
In a preferred embodiment, the contact pressure between the casing 2790 and the existing
25 section of wellbore casing ranges from about 400 to 1 0,000 in order to optimally provide
contact pressure for activating the sealing members, provide optimal resistance to axial
movement of the expanded casing, and optimally resist typical tensile and compressive
loads on the expanded casing.
In a preferred embodiment, as the expansion cone 2765 nears the end of the casing
30 2790, the operating pressure of the second fluidic material is reduced in order to minimize
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shock to the apparatus 2700. In an alternative embodiment, the apparatus 2700 includes
a shock absorber for absorbing the shock created by the completion of the radial expansion
of the casing 2790.
In a preferred embodiment, the reduced operating pressure of the second fluidic
5 material ranges from about 100 to 1 ,000 psi (6.8947 to 68.947 bar) as the expansion cone
2765 nears the end of the casing 2790 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2765. In a preferred embodiment, the
operating pressure of the second fluidic material is reduced during the return stroke of the
apparatus 2700 to the range of about 0 to 500 psi (0 to 34.47 bar) in order minimize the
10 resistance to the movement of the expansion cone 2765 during the return stroke. In a
preferred embodiment, the stroke length of the apparatus 2700 ranges from about 1 0 to 45
feet (3.048 to 13.716 metres) in order to optimally provide equipment that can be easily
handled by typical oil well rigging equipment and minimize the frequency at which the
apparatus 2700 must be re-stroked during an expansion operation.
15 In an alternative embodiment, at least a portion of the upper sealing heads, 2725
and 2745, include expansion cones for radially expanding the mandrel launcher 2770 and
casing 2790 during operation of the apparatus 2700 in order to increase the surface area
of the casing 2790 acted upon during the radial expansion process. In this manner, the
operating pressures can be reduced.
20 In an alternative embodiment, mechanical slips are positioned in an axial location
between the sealing sleeve 1915 and the first inner sealing mandrel 2720 in order to
optimally provide a simplified assembly and operation of the apparatus 2700.
Upon the complete radial expansion of the casing 2790, if applicable, the first
fluidic material is permitted to cure within the annular region between the outside of the
25 expanded casing 2790 and the interior walls of the wellbore. In the case where the casing
2790 is slotted, the cured fluidic material preferably permeates and envelops the expanded
casing 2790. In this manner, a new section of wellbore casing is formed within a
wellbore. Alternatively, the apparatus 2700 may be used to join a first section of pipeline
to an existing section of pipeline. Alternatively, the apparatus 2700 may be used to
30 directly line the interior of a wellbore with a casing, without the use of an outer annular
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layer of a hardenable material. Alternatively, the apparatus 2700 may be used to expand
a tubular support member in a hole.
During the radial expansion process, the pressurized areas of the apparatus 2700
are limited to the fluid passages 2795, 2800, 2802, 2805, and 2810, and the pressure
5 chambers 2915 and 2920. No fluid pressure acts directly on the mandrel launcher 2770
and casing 2790. This permits the use of operating pressures higher than the mandrel
launcher 2770 and casing 2790 could normally withstand.
Referring now to Figure 20, a preferred embodiment of an apparatus 3000 for
forming a mono-diameter wellbore casing will be described. The apparatus 3000
10 preferably includes a drillpipe 3005, an innerstring adapter 3010, a sealing sleeve 3015,
a first inner sealing mandrel 3020, hydraulic slips 3025, a first upper sealing head 3030,
a first lower sealing head 3035, a first outer sealing mandrel 3040, a second inner sealing
mandrel 3045, a second upper sealing head 3050, a second lower sealing head 3055, a
second outer sealing mandrel 3060, load mandrel 3065, expansion cone 3070, casing
15 3075, and fluid passages 3080, 3085, 3090, 3095, 3100, 3105, 31 10, 31 15 and 3120.
The drillpipe 3005 is coupled to (he innerstring adapter 3010. During operation
of the apparatus 3000, the drillpipe 3005 supports the apparatus 3000. The drillpipe 3005
preferably comprises a substantially hollow tubular member or members. The drillpipe
3005 may be fabricated from any number of conventional commercially available
20 materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
drillpipe 3005 is fabricated from coiled tubing in order to faciliate the placement of the
apparatus 3000 in non-vertical wellbores. The drillpipe 3005 may be coupled to the
innerstring adapter 3010 using any number of conventional commercially available
25 mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, or a standard threaded connection. In a preferred
embodiment, the drillpipe 3005 is removably coupled to the innerstring adapter 3010 by
a drillpipe connection.
The drillpipe 3005 preferably includes a fluid passage 3080 that is adapted to
30 convey fluidic materials from a surface location into the fluid passage 3085. In a preferred
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embodiment, the fluid passage 3080 is adapted to convey fluidic materials such as, for
example, cement, epoxy, water, drilling mud or lubricants at operating pressures and flow
rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to 620.52« bar
and 0 to 1 1356.24 litres/minute).
5 The innerstring adapter 3010 is coupled to the drill string 3005 and the sealing
sleeve 3015. The innerstring adapter 3010 preferably comprises a substantially hollow
tubular member or members. The innerstring adapter 3010 may be fabricated from any
number of conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel, or other similar high
10 strength materials. In a preferred embodiment, the innerstring adapter 301 0 is fabricated
from stainless steel in order to optimally provide high strength, corrosion resistance, and
low friction surfaces.
The innerstring adapter 3010 may be coupled to the drill string 3005 using any
number of conventional commercially available mechanical couplings such as, for
15 example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, or a standard threaded connection. In a preferred embodiment, the innerstring
adapter 3010 is removably coupled to the drill pipe 3005 by a drillpipe connection. The
innerstring adapter 3010 may be coupled to the sealing sleeve 3015 using any number of
conventional commercially available mechanical couplings such as, for example, drillpipe
20 connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch
type threaded connection or a standard threaded connection. In a preferred embodiment,
the innerstring adapter 301 0 is removably coupled to the sealing sleeve 30 1 5 by a standard
threaded connection.
The innerstring adapter 3010 preferably includes a fluid passage 3085 that is
25 adapted to convey fluidic materials from the fluid passage 3080 into the fluid passage
3090. In a preferred embodiment, the fluid passage 3085 is adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling mud, or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
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The sealing sleeve 3015 is coupled to the innerstring adapter 3010 and the first
inner sealing mandrel 3020. The sealing sleeve 3015 preferably comprises a substantially
hollow tubular member or members. The sealing sleeve 30 1 5 may be fabricated from any
number of conventional commercially available materials such as, for example, oilfield
5 country tubular goods, low alloy steel, carbon steel, stainless steel or other similar high
strength materials. In a preferred embodiment, the sealing sleeve 3015 is fabricated from
stainless steel in order to optimally provide high strength, corrosion resistance, and low
friction surfaces.
The sealing sleeve 3015 may be coupled to the innerstring adapter 3010 using any
10 number of conventional commercially available mechanical couplings such as, for
example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, ratchet-latch type connection or a standard threaded connection. In a
preferred embodiment, the sealing sleeve 3015 is removably coupled to the innerstring
adapter 30 1 0 by a standard threaded connection. The sealing sleeve 3015 may be coupled
15 to the first inner sealing mandrel 3020 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection, oilfield country
tubular goods specialty type threaded connection, ratchet-latch type threaded connection
or a standard threaded connection. In a preferred embodiment, the sealing sleeve 301 5 is
removably coupled to the first inner sealing mandrel 3020 by a standard threaded
20 connection,
The sealing sleeve 3015 preferably includes a fluid passage 3090 that is adapted
to convey fluidic materials from the fluid passage 3085 into the fluid passage 3095. In a
preferred embodiment, the fluid passage 3090 is adapted to convey fluidic materials such
as, for example, cement, epoxy, water, drilling mud, or lubricants at operating pressures
25 and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356.24 litres/minute).
The first inner sealing mandrel 3020 is coupled to the sealing sleeve 3015, the
hydraulic slips 3025, and the first lower sealing head 3035. The first inner sealing
mandrel 3020 is further movably coupled to the first upper sealing head 3030. The first
30 inner sealing mandrel 3020 preferably comprises a substantially hollow tubular member
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or members. The first inner sealing mandrel 3020 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield country
tubular goods, low alloy steel, carbon steel, stainless steel, or similar high strength
materials. In a preferred embodiment, the first inner sealing mandrel 3020 is fabricated
5 from stainless steel in order to optimally provide high strength, corrosion resistance, and
low friction surfaces.
The first inner sealing mandrel 3020 may be coupled to the sealing sleeve 3015
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
10 connection, ratchet-latch type threaded connection or a standard threaded connection. In
a preferred embodiment, the first inner sealing mandrel 3020 is removably coupled to the
sealing sleeve 301 5 by a standard threaded connection. The first inner sealing mandrel
3020 may be coupled to the hydraulic slips 3025 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe connection,
15 oilfield country tubular goods specialty type threaded connection, ratchet-latch type
threaded connection or a standard threaded connection. In a preferred embodiment, the
first inner sealing mandrel 3020 is removably coupled to the hydraulic slips 3025 by a
standard threaded connection. The first inner sealing mandrel 3020 may be coupled to the
first lower sealing head 3035 using any number of conventional commercially available
20 mechanical couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, ratchet-latch type threaded connection or a
standard threaded connection. In a preferred embodiment, the first inner sealing mandrel
3020 is removably coupled to the first lower sealing head 3035 by a standard threaded
connection.
25 The first inner sealing mandrel 3020 preferably includes a fluid passage 3095 that
is adapted to convey fluidic materials from the fluid passage 3090 into the fluid passage
3100. In a preferred embodiment, the fluid passage 3095 is adapted to convey fluidic
materials such as, for example, water, drilling mud, cement, epoxy, or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
30 gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
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The first inner sealing mandrel 3020 further preferably includes fluid passages
3110 that are adapted to convey fluidic materials from the fluid passage 3095 into the
pressure chambers of the hydraulic slips 3025. In this manner, the slips 3025 are activated
upon the pressurization of the fluid passage 3095 into contact with the inside surface of
5 the casing 3075. In a preferred embodiment, the fluid passages 31 10 are adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling fluids or
lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0
to 3,000 gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The first inner sealing mandrel 3020 further preferably includes fluid passages
10 3115 that are adapted to convey fluidic materials from the fluid passage 3095 into the first
pressure chamber 3175 defined by the first upper sealing head 3030, the first lower sealing
head 3035, the first inner sealing mandrel 3020, and the first outer sealing mandrel 3040.
During operation of the apparatus 3000, pressurization of the pressure chamber 3175
causes the first upper sealing head 3030, the first outer sealing mandrel 3040, the second
15 upper sealing head 3050, the second outer sealing mandrel 3060, and the expansion cone
3070 to move in an axial direction.
The slips 3025 are coupled to the outside surface of the first inner sealing mandrel
3020. During operation of the apparatus 3000, the slips 3025 are activated upon the
pressurization of the fluid passage 3095 into contact with the inside surface of the casing
20 3075. In this manner, the slips 3025 maintain the casing 3075 in a substantially stationary
position.
The slips 3025 preferably include fluid passages 3 125, pressure chambers 3 130,
spring bias 3135, and slip members 3 140. The slips 3025 may comprise any number of
conventional commercially available hydraulic slips such as, for example, RTTS packer
25 tungsten carbide hydraulic slips or Model 3L retrievable bridge plug with hydraulic slips.
In a preferred embodiment, the slips 3025 comprise RTTS packer tungsten carbide
hydraulic slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 3075 during the expansion process.
The first upper sealing head 3030 is coupled to the first outer sealing mandrel
30 3040, the second upper sealing head 3050, the second outer sealing mandrel 3060, and the
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expansion cone 3070. The first upper sealing head 3030 is also movably coupled to the
outer surface of the first inner sealing mandrel 3020 and the inner surface of the casing
3075. In this manner, the first upper sealing head 3030, the first outer sealing mandrel
3040, the second upper sealing head 3050, the second outer sealing mandrel 3060, and the
5 expansion cone 3070 reciprocate in the axial direction.
The radial clearance between the inner cylindrical surface of the first upper sealing
head 3030 and the outer surface of the first inner sealing mandrel 3020 may range, for
example, from about 0.0025 to 0.05 inches (0.00635 to 0. 1 27 centimetres). In a preferred
embodiment, the radial clearance between the inner cylindrical surface of the first upper
10 sealing head 3030 and the outer surface of the first inner sealing mandrel 3020 ranges
from about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres) in order to optimally
provide minimal radial clearance. The radial clearance between the outer cylindrical
surface of the first upper sealing head 3030 and the inner surface of the casing 3075 may
range, for example, from about 0.025 to 0.375 inches (0.0635 to 0.9525 centimetres). In
15 a preferred embodiment, the radial clearance between the outer cylindrical surface of the
first upper sealing head 3030 and the inner surface of the casing 3075 ranges from about
0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in order to optimally provide
stabilization for the expansion cone 3070 during the expansion process.
The first upper sealing head 3030 preferably comprises an annular member having
20 substantially cylindrical inner and outer surfaces. The first upper sealing head 3030 may
be fabricated from any number of conventional commercially available materials such as,
for example, oilfield country tubular goods, low alloy steel, carbon steel, or other similar
high strength materials. In a preferred embodiment, the first upper sealing head 3030 is
fabricated from stainless steel in order to optimally provide high strength, corrosion
25 resistance, and low friction surfaces. The inner surface of the first upper sealing head
3030 preferably includes one or more annular sealing members 3145 for sealing the
interface between the first upper sealing head 3030 and the first inner sealing mandrel
3020. The sealing members 3145 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings, polypak
30 seals or metal spring energized seals. In a preferred embodiment, the sealing members
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3145 comprise polypak seals available from Parker seals in order to optimally provide
sealing for a long axial stroke.
In a preferred embodiment, the first upper sealing head 3030 includes a shoulder
3150 for supporting the first upper sealing head 3030, first outer sealing mandrel 3040,
5 second upper sealing head 3050, second outer sealing mandrel 3060, and expansion cone
3070 on the first lower sealing head 3035.
The first upper sealing head 3030 may be coupled to the first outer sealing mandrel
3040 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty type
10 threaded connection, or a standard threaded connection. In a preferred embodiment, the
first upper sealing head 3030 is removably coupled to the first outer sealing mandrel 3040
by a standard threaded connection. In a preferred embodiment, the mechanical coupling
between the first upper sealing head 3030 and the first outer sealing mandrel 3040
includes one or more sealing members 3 1 55 for fluidicly sealing the interface between the
15 first upper sealing head 3030 and the first outer sealing mandrel 3040. The sealing
members 3 1 55 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals, or metal spring energized seals. In
a preferred embodiment, the sealing members 3155 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
20 The first lower sealing head 3035 is coupled to the first inner sealing mandrel 3020
and the second inner sealing mandrel 3045. The first lower sealing head 3035 is also
movably coupled to the inner surface of the first outer sealing mandrel 3040. In this
manner, the first upper sealing head 3030, first outer sealing mandrel 3040, second upper
sealing head 3050, second outer sealing mandrel 3060, and expansion cone 3070
25 reciprocate in the axial direction. The radial clearance between the outer surface of the
first lower sealing head 3035 and the inner surface of the first outer sealing mandrel 3040
may range, for example, from about 0.0025 to 0.05 inches (0.00635 to 0. 1 27 centimetres).
In a preferred embodiment, the radial clearance between the outer surface of the first lower
sealing head 3035 and the inner surface of the outer sealing mandrel 3040 ranges from
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about 0.005 to 0.01 inches (0.0127 to 0.254 centimetres) in order to optimally provide
minimal radial clearance.
The first lower sealing head 303 5 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The first lower sealing head 3035 may
5 be fabricated from any number of conventional commercially available materials such as,
for example, oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other similar high strength materials. In a preferred embodiment, the first lower sealing
head 3035 is fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the first lower sealing
10 head 3035 preferably includes one or more annular sealing members 3 1 60 for sealing the
interface between the first lower sealing head 3035 and the first outer sealing mandrel
3040. The sealing members 3160 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings, polypak
seals, or metal spring energized seals. In a preferred embodiment, the sealing members
15 3 160 comprise polypak seals available from Parker Seals in order to optimally provide
sealing for a long axial stroke.
The first lower sealing head 3035 may be coupled to the first inner sealing mandrel
3020 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty type
20 threaded connection, ratchet-latch type threaded connection or a standard threaded
connection. In a preferred embodiment, the first lower sealing head 3035 is removably
coupled to the first inner sealing mandrel 3020 by a standard threaded connection. In a
preferred embodiment, the mechanical coupling between the first lower sealing head 3035
and the first inner sealing mandrel 3020 includes one or more sealing members 3165 for
2 5 fluidicly sealing the interface between the first lower sealing head 303 5 and the first inner
sealing mandrel 3020. The sealing members 3165 may comprise any number of
conventional commercially available sealing members such as, for example, o-rings,
polypak seals, or metal spring energized seals. In a preferred embodiment, the sealing
members 3 165 comprise polypak seals available from Parker Seals in order to optimally
30 provide sealing for a long axial stroke length.
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The first lower sealing head 3035 may be coupled to the second inner sealing
mandrel 3045 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type threaded connection or a standard
5 threaded connection. In a preferred embodiment, the first lower sealing head 3035 is
removably coupled to the second inner sealing mandrel 3045 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the first lower
sealing head 3035 and the second inner sealing mandrel 3045 includes one or more sealing
members 3 1 70 for fluidicly sealing the interface between the first lower sealing head 303 5
10 and the second inner sealing mandrel 3045. The sealing members 3 1 70 may comprise any
number of conventional commercially available sealing members such as, for example,
o-rings, polypak seals or metal spring energized seals. In a preferred embodiment, the
sealing members 3170 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
1 5 The first outer sealing mandrel 3040 is coupled to the first upper sealing head 3030
and the second upper sealing head 3050. The first outer sealing mandrel 3040 is also
movably coupled to the inner surface of the casing 3075 and the outer surface of the first
lower sealing head 3035. In this manner, the first upper sealing head 3030, first outer
sealing mandrel 3040, second upper sealing head 3050, second outer sealing mandrel
20 3060, and the expansion cone 3070 reciprocate in the axial direction. The radial clearance
between the outer surface of the first outer sealing mandrel 3040 and the inner surface of
the casing 3075 may range, for example, from about 0.025 to 0.375 inches (0.0635 to
0.9525 centimetres). In a preferred embodiment, the radial clearance between the outer
surface of the first outer sealing mandrel 3040 and the inner surface of the casing 3075
25 ranges from about 0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in order to
optimally provide stabilization for the expansion cone 3070 during the expansion process.
The radial clearance between the inner surface of the first outer sealing mandrel 3040 and
the outer surface of the first lower sealing head 3035 may range, for example, from about
0.005 to 0.125 inches (0.0127 to 0.3175 centimetres). In a preferred embodiment, the
30 radial clearance between the inner surface of the first outer sealing mandrel 3040 and the
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outer surface of the first lower sealing head 3035 ranges from about 0.005 to 0.01 inches
(0.0127 to 0.254 centimetres) in order to optimally provide minimal radial clearance.
The first outer sealing mandrel 3040 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The first outer sealing mandrel
5 3040 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the first
outer sealing mandrel 3040 is fabricated from stainless steel in order to optimally provide
high strength, corrosion resistance, and low friction surfaces.
1 0 The first outer sealing mandrel 3040 may be coupled to the first upper sealing head
3030 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty type
threaded connection, ratchet-latch type threaded connection or a standard threaded
connection. In a preferred embodiment, the first outer sealing mandrel 3040 is removably
15 coupled to the first upper sealing head 3030 by a standard threaded connection. In a
preferred embodiment, the mechanical coupling between the first outer sealing mandrel
3040 and the first upper sealing head 3030 includes one or more sealing members 3180
for sealing the interface between the first outer sealing mandrel 3040 and the first upper
sealing head 3030. The sealing members 3 1 80 may comprise any number of conventional
20 commercially available sealing members such as, for example, o-rings, polypak seals or
metal spring energized seals. In a preferred embodiment, the sealing members 3180
comprise polypak seals available from Parker Seals in order to optimally provide sealing
for a long axial stroke.
The first outer sealing mandrel 3040 may be coupled to the second upper sealing
25 head 3050 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type threaded connection, or a standard
threaded connection. In a preferred embodiment, the first outer sealing mandrel 3040 is
removably coupled to the second upper sealing head 3050 by a standard threaded
30 connection. In a preferred embodiment, the mechanical coupling between the first outer
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sealing mandrel 3040 and the second upper sealing head 3050 includes one or more
sealing members 3185 for sealing the interface between the first outer sealing mandrel
3040 and the second upper sealing head 3050. The sealing members 3 1 85 may comprise
any number of conventional commercially available sealing members such as, for
5 example, o-rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 3185 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial stroke.
The second inner sealing mandrel 3045 is coupled to the first lower sealing head
3035 and the second lower sealing head 3055. The second inner sealing mandrel 3045
10 preferably comprises a substantially hollow tubular member or members. The second
inner sealing mandrel 3045 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength materials. In a
preferred embodiment, the second inner sealing mandrel 3045 is fabricated from stainless
15 steel in order to optimally provide high strength, corrosion resistance, and low friction
surfaces.
The second inner sealing mandrel 3045 may be coupled to the first lower sealing
head 3035 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
20 specialty type threaded connection, ratchet-latch type threaded connection or a standard
threaded connection. In a preferred embodiment, the second inner sealing mandrel 3045
is removably coupled to the first lower sealing head 3035 by a standard threaded
connection. The second inner sealing mandrel 3045 may be coupled to the second lower
sealing head 3055 using any number of conventional commercially available mechanical
25 couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type connection, or a standard threaded
connection. In a preferred embodiment, the second inner sealing mandrel 3045 is
removably coupled to the second lower sealing head 3055 by a standard threaded
connection.
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The second inner sealing mandrel 3045 preferably includes a fluid passage 3100
that is adapted to convey fluidic materials from the fluid passage 3095 into the fluid
passage 3105. In a preferred embodiment, the fluid passage 3100 is adapted to convey
fluidic materials such as, for example, cement, epoxy, water, drilling mud or lubricants at
5 operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The second inner sealing mandrel 3045 further preferably includes fluid passages
3120 that are adapted to convey fluidic materials from the fluid passage 3100 into the
second pressure chamber 3 190 defined by the second upper sealing head 3050, the second
10 lower sealing head 3055, the second inner sealing mandrel 3045, and the second outer
sealing mandrel 3060. During operation of the apparatus 3000, pressurization of the
second pressure chamber 3190 causes the first upper sealing head 3030, the first outer
sealing mandrel 3040, the second upper sealing head 3050, the second outer sealing
mandrel 3060, and the expansion cone 3070 to move in an axial direction.
15 The second upper sealing head 3050 is coupled to the first outer sealing mandrel
3040 and the second outer sealing mandrel 3060. The second upper sealing head 3050 is
also movably coupled to the outer surface of the second inner sealing mandrel 3045 and
the inner surface of the casing 3075. In this manner, the second upper sealing head 3050
reciprocates in the axial direction. The radial clearance between the inner cylindrical
20 surface of the second upper sealing head 3050 and the outer surface of the second inner
sealing mandrel 3045 may range, for example, from about 0.0025 to 0.05 inches (0.00635
to 0. 1 27 centimetres). In a preferred embodiment, the radial clearance between the inner
cylindrical surface of the second upper sealing head 3050 and the outer surface of the
second inner sealing mandrel 3045 ranges from about 0.005 to 0.01 inches (0.0127 to
25 0.254 centimetres) in order to optimally provide minimal radial clearance. The radial
clearance between the outer cylindrical surface of the second upper sealing head 3050 and
the inner surface of the casing 3075 may range, for example, from about 0.025 to 0.375
inches (0.0635 to 0.9525 centimetres). In a preferred embodiment, the radial clearance
between the outer cylindrical surface of the second upper sealing head 3050 and the inner
30 surface of the casing 3075 ranges from about 0.025 to 0.125 inches (0.0635 to 0.3175
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centimetres) in order to optimally provide stabilization for the expansion cone 3070 during
the expansion process.
The second upper sealing head 3050 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The second upper sealing head
5 3050 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel or other similar high strength materials. In a preferred embodiment, the
second upper sealing head 3050 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces. The inner surface
10 of the second upper sealing head 3050 preferably includes one or more annular sealing
members 3 1 95 for sealing the interface between the second upper sealing head 3050 and
the second inner sealing mandrel 3045. The sealing members 3195 may comprise any
number of conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a preferred
15 embodiment, the sealing members 3195 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for a long axial stroke.
In a preferred embodiment, the second upper sealing head 3050 includes a shoulder
3200 for supporting the first upper sealing head 3030, first outer sealing mandrel 3040,
second upper sealing head 3050, second outer sealing mandrel 3060, and expansion cone
20 3070 on the second lower sealing head 3055.
The second upper sealing head 3050 may be coupled to the first outer sealing
mandrel 3040 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type threaded connection, or a standard
25 threaded connection. In a preferred embodiment, the second upper sealing head 3050 is
removably coupled to the first outer sealing mandrel 3040 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the second
upper sealing head 3050 and the first outer sealing mandrel 3040 includes one or more
sealing members 3 1 85 for fluidicly sealing the interface between the second upper sealing
30 head 3050 and the first outer sealing mandrel 3040. The second upper sealing head 3050
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may be coupled to the second outer sealing mandrel 3060 using any number of
conventional commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection, ratchet-latch
type threaded connection, or a standard threaded connection. In a preferred embodiment,
5 the second upper sealing head 3050 is removably coupled to the second outer sealing
mandrel 3060 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the second upper sealing head 3050 and the second outer
sealing mandrel 3060 includes one or more sealing members 3205 for fluidicly sealing the
interface between the second upper sealing head 3050 and the second outer sealing
10 mandrel 3060.
The second lower sealing head 3055 is coupled to the second inner sealing mandrel
3045 and the load mandrel 3065. The second lower sealing head 3055 is also movably
coupled to the inner surface of the second outer sealing mandrel 3060. In this manner, the
first upper sealing head 3030, first outer sealing mandrel 3040, second upper sealing
15 mandrel 3050, second outer sealing mandrel 3060, and expansion cone 3070 reciprocate
in the axial direction. The radial clearance between the outer surface of the second lower
sealing head 3055 and the inner surface of the second outer sealing mandrel 3060 may
range, for example, from about 0.0025 to 0.05 inches (0.00635 to 0. 127 centimetres). In
a preferred embodiment, the radial clearance between the outer surface of the second
20 lower sealing head 3055 and the inner surface of the second outer sealing mandrel 3060
ranges from about 0.005 to 0.0 1 inches (0.0 1 27 to 0.254 centimetres) in order to optimally
provide minimal radial clearance.
The second lower sealing head 3055 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The second lower sealing head
25 3055 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel, or other similar high strength materials. In a preferred embodiment, the
second lower sealing head 3055 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces. The outer surface
30 of the second lower sealing head 3055 preferably includes one or more annular sealing
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members 32 10 for sealing the interface between the second lower sealing head 3055 and
the second outer sealing mandrel 3060. The sealing members 3210 may comprise any
number of conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a preferred
5 embodiment, the sealing members 3210 comprise polypak seals available from Parker
Seals in order to optimally provide sealing for long axial strokes.
The second lower sealing head 3055 may be coupled to the second inner sealing
mandrel 3045 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular goods
10 specialty type threaded connection, or a standard threaded connection. In a preferred
embodiment, the second lower sealing head 3055 is removably coupled to the second
inner sealing mandrel 3045 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the lower sealing head 3055 and the
second inner sealing mandrel 3045 includes one or more sealing members 3215 for
15 fluidicly sealing the interface between the second lower sealing head 3055 and the second
inner sealing mandrel 3045. The sealing members 3215 may comprise any number of
conventional commercially available sealing members such as, for example, o-rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the sealing
members 32 1 5 comprise polypak seals available from Parker Seals in order to optimally
20 provide sealing for long axial strokes.
The second lower sealing head 3055 may be coupled to the load mandrel 3065
using any number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty type threaded
connection, or a standard threaded connection. In a preferred embodiment, the second
25 lower sealing head 3055 is removably coupled to the load mandrel 3065 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling between the
second lower sealing head 3055 and the load mandrel 3065 includes one or more sealing
members 3220 for fluidicly sealing the interface between the second lower sealing head
3055 and the load mandrel 3065. The sealing members 3220 may comprise any number
30 of conventional commercially available sealing members such as, for example, o-rings,
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polypak seals or metal spring energized seals. In a preferred embodiment, the sealing
members 3220 comprise polypak seals available from Parker Seals in order to optimally
provide sealing for a long axial stroke.
In a preferred embodiment, the second lower sealing head 3055 includes a throat
5 passage 3225 fluidicly coupled between the fluid passages 3100 and 3105. The throat
passage 3225 is preferably of reduced size and is adapted to receive and engage with a
plug 3230, or other similar device. In this manner, the fluid passage 3100 is fluidicly
isolated from the fluid passage 3105. In this manner, the pressure chambers 3175 and
3 190 are pressurized. Furthermore, the placement of the plug 3230 in the throat passage
10 3225 also pressurizes the pressure chambers 3 130 of the hydraulic slips 3025.
The second outer sealing mandrel 3060 is coupled to the second upper sealing head
3050 and the expansion cone 3070. The second outer sealing mandrel 3060 is also
movably coupled to the inner surface of the casing 3075 and the outer surface of the
second lower sealing head 3055. In this manner, the first upper sealing head 3030, first
1 5 outer sealing mandrel 3040, second upper sealing head 3050, second outer sealing mandrel
3060, and the expansion cone 3070 reciprocate in the axial direction. The radial clearance
between the outer surface of the second outer sealing mandrel 3060 and the inner surface
of the casing 3075 may range, for example, from about 0.025 to 0.375 inches (0.0635 to
0.9525 centimetres). In a preferred embodiment, the radial clearance between the outer
20 surface of the second outer sealing mandrel 3060 and the inner surface of the casing 3075
ranges from about 0.025 to 0.125 inches (0.0635 to 0.3175 centimetres) in order to
optimally provide stabilization for the expansion cone 3070 during the expansion process.
The radial clearance between the inner surface of the second outer sealing mandrel 3060
and the outer surface of the second lower sealing head 3055 may range, for example, from
25 about 0.0025 to 0.05 inches (0.00635 to 0.127 centimetres). In a preferred embodiment,
the radial clearance between the inner surface of the second outer sealing mandrel 3060
and the outer surface of the second lower sealing head 3055 ranges from about 0.005 to
0.01 inches (0.0127 to 0.254 centimetres) in order to optimally provide minimal radial
clearance.
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The second outer sealing mandrel 3060 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The second outer sealing
mandrel 3060 maybe fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy steel, carbon steel,
5 stainless steel or other similar high strength materials. In a preferred embodiment, the
second outer sealing mandrel 3060 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces.
The second outer sealing mandrel 3060 may be coupled to the second upper sealing
head 3050 using any number of conventional commercially available mechanical
10 couplings such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, or a standard threaded connection. In a preferred
embodiment, the outer sealing mandrel 3060 is removably coupled to the second upper
sealing head 3050 by a standard threaded connection. The second outer sealing mandrel
3060 may be coupled to the expansion cone 3070 using any number of conventional
15 commercially available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, or a standard threaded
connection. In a preferred embodiment, the second outer sealing mandrel 3060 is
removably coupled to the expansion cone 3070 by a standard threaded connection.
The first upper sealing head 3030, the first lower sealing head 3035, the first inner
20 sealing mandrel 3020, and the first outer sealing mandrel 3040 together define the first
pressure chamber 3175. The second upper sealing head 3050, the second lower sealing
head 3055, the second inner sealing mandrel 3045, and the second outer sealing mandrel
3060 together define the second pressure chamber 3 190. The first and second pressure
chambers, 3 175 and 3190, are fluidicly coupled to the passages, 3095 and 3 100, via one
25 or more passages, 3115 and3120. During operation ofthe apparatus 3000, the plug 3230
engages with the throat passage 3225 to fluidicly isolate the fluid passage 3 100 from the
fluid passage 3105. The pressure chambers, 3175 and 3190, are then pressurized which
in turn causes the first upper sealing head 3030, the first outer sealing mandrel 3040, the
second upper sealing head 3050, the second outer sealing mandrel 3060, and expansion
30 cone 3070 to reciprocate in the axial direction. The axial motion ofthe expansion cone
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3070 in turn expands the casing 3075 in the radial direction. The use of a plurality of
pressure chambers, 3175 and 3190, effectively multiplies the available driving force for
the expansion cone 3070.
The load mandrel 3065 is coupled to the second lower sealing head 3055. The load
5 mandrel 3065 preferably comprises an annular member having substantially cylindrical
inner and outer surfaces. The load mandrel 3065 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield country
tubular goods, low alloy steel, carbon steel, stainless steel or other similar high strength
materials. In a preferred embodiment, the load mandrel 3065 is fabricated from stainless
10 steel in order to optimally provide high strength, corrosion resistance, and low friction
surfaces.
The load mandrel 3065 may be coupled to the lower sealing head 3055 using any
number of conventional commercially available mechanical couplings such as, for
example, epoxy, cement, water, drilling mud, or lubricants. In a preferred embodiment,
15 the load mandrel 3065 is removably coupled to the lower sealing head 3055 by a standard
threaded connection. The load mandrel 3065 preferably includes a fluid passage
3 1 05 that is adapted to convey fluidic materials from the fluid passage 3 100 to the region
outside of the apparatus 3000. In a preferred embodiment, the fluid passage 3105 is
adapted to convey fluidic materials such as, for example, cement, epoxy, water, drilling
20 mud or lubricants at operating pressures and flow rates ranging from about 0 to 9,000 psi
and 0 to 3,000 gallons/minute (0 to 620.528 bar and 0 to 1 1356.24 litres/minute).
The expansion cone 3070 is coupled to the second outer sealing mandrel 3060.
The expansion cone 3070 is also movably coupled to the inner surface of the casing 3075.
In this manner, the first upper sealing head 3030, first outer sealing mandrel 3040, second
25 upper sealing head 3050, second outer sealing mandrel 3060, and the expansion cone 3070
reciprocate in the axial direction. The reciprocation of the expansion cone 3070 causes
the casing 3075 to expand in the radial direction.
The expansion cone 3070 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius of the outside
30 conical surface may range, for example, from about 2 to 34 inches (5.08 to 86.36
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centimetres). In a preferred embodiment, the outside radius of the outside conical surface
ranges from about 3 to 28 inches (7.62 to 71.12 centimetres) in order to optimally provide
an expansion cone 3070 for expanding typical casings. The axial length of the expansion
cone 3070 may range, for example, from about 2 to 8 times the maximum outer diameter
5 of the expansion cone 3070. In a preferred embodiment, the axial length of the expansion
cone 3070 ranges from about 3 to 5 times the maximum outer diameter of the expansion
cone 3070 in order to optimally provide stabilization and centralization of the expansion
cone 3070 during the expansion process. In a particularly preferred embodiment, the
maximum outside diameter of the expansion cone 3070 is between about 95 to 99 % of
10 the inside diameter of the existing wellbore that the casing 3075 will be joined with. In
a preferred embodiment, the angle of attack of the expansion cone 3070 ranges from about
5 to 30 degrees in order to optimally balance the frictional forces with the radial expansion
forces.
The expansion cone 3070 may be fabricated from any number of conventional
15 commercially available materials such as, for example, machine tool steel, nitride steel,
titanium, tungsten carbide, ceramics, or other similar high strength materials. In a
preferred embodiment, the expansion cone 3070 is fabricated from D2 machine tool steel
in order to optimally provide high strength and resistance to wear and galling. In a
particularly preferred embodiment, the outside surface of the expansion cone 3070 has a
20 surface hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength and resistance to wear and galling.
The expansion cone 3070 may be coupled to the second outside sealing mandrel
3060 using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods specialty type
25 threaded connection, ratchet-latch type connection or a standard threaded connection. In
a preferred embodiment, the expansion cone 3070 is coupled to the second outside sealing
mandrel 3060 using a standard threaded connection in order to optimally provide high
strength and easy disassembly.
The casing 3075 is removably coupled to the slips 3025 and the expansion cone
30 3070. The casing 3075 preferably comprises a tubular member. The casing 3075 may be
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fabricated from any number of conventional commercially available materials such as, for
example, slotted tubulars, oilfield country tubular goods, carbon steel, low alloy steel,
stainless steel, or other similar high strength materials. In a preferred embodiment, the
casing 3075 is fabricated from oilfield country tubular goods available from various
5 foreign and domestic steel mills in order to optimally provide high strength.
In a preferred embodiment, the upper end 3235 of the casing 3075 includes a thin
wall section 3240 and an outer annular sealing member 3245. In a preferred embodiment,
the wall thickness of the thin wall section 3240 is about 50 to 100 % of the regular wall
thickness of the casing 3075. In this manner, the upper end 3235 of the casing 3075 may
10 be easily radially expanded and deformed into intimate contact with the lower end of an
existing section of wellbore casing. In a preferred embodiment, the lower end of the
existing section of casing also includes a thin wall section. In this manner, the radial
expansion of the thin walled section 3240 of casing 3075 into the thin walled section of
the existing wellbore casing results in a wellbore casing having a substantially constant
15 inside diameter.
The annular sealing member 3245 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, epoxy,
rubber, metal or plastic. In a preferred embodiment, the annular sealing member 3245 is
fabricated from StrataLock epoxy in order to optimally provide compressibility and wear
20 resistance. The outside diameter of the annular scaling member 3245 preferably ranges
from about 70 to 95 % of the inside diameter of the lower section of the wellbore casing
that the casing 3075 is joined to. In this manner, after radial expansion, the annular
sealing member 3245 optimally provides a fluidic seal and also preferably optimally
provides sufficient frictional force with the inside surface of the existing section of
25 wellbore casing during the radial expansion of the casing 3075 to support the casing 3075.
In a preferred embodiment, the lower end 3250 of the casing 3075 includes a thin
wall section 3255 and an outer annular sealing member 3260. In a preferred embodiment,
the wall thickness of the thin wall section 3255 is about 50 to 100 % of the regular wall
thickness of the casing 3075. In this manner, the lower end 3250 of the casing 3075 may
30 be easily expanded and deformed. Furthermore, in this manner, an other section of casing
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may be easily joined with the lower end 3250 of the casing 3075 using a radial expansion
process. In a preferred embodiment, the upper end of the other section of casing also
includes a thin wall section. In this manner, the radial expansion of the thin walled section
of the upper end of the other casing into the thin walled section 3255 of the lower end
5 3250 of the casing 3075 results in a wellbore casing having a substantially constant inside
diameter.
The upper annular sealing member 3245 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, epoxy,
rubber, metal or plastic. In a preferred embodiment, the upper annular sealing member
10 3245 is fabricated from Stratalock epoxy in order to optimally provide compressibility and
resistance to wear. The outside diameter of the upper annular sealing member 3245
preferably ranges from about 70 to 95 % of the inside diameter of the lower section of the
existing wellbore casing that the casing 3075 is joined to. In this manner, after radial
expansion, the upper annular sealing member 3245 preferably provides a fluidic seal and
15 also preferably provides sufficient frictional force with the inside wall of the wellbore
during the radial expansion of the casing 3075 to support the casing 3075.
The lower annular sealing member 3260 may be fabricated from any number of
conventional commercially available sealing materials such as, for example, epoxy,
rubber, metal or plastic. In a preferred embodiment, the lower annular sealing member
20 3260 is fabricated from StrataLock epoxy in order to optimally provide compressibility
and resistance to wear. The outside diameter of the lower annular sealing member 3260
preferably ranges from about 70 to 95 % of the inside diameter of the lower section of the
existing wellbore casing that the casing 3075 is joined to. In this manner, the lower
annular sealing member 3260 preferably provides a fluidic seal and also preferably
25 provides sufficient frictional force with the inside wall of the wellbore during the radial
expansion of the casing 3075 to support the casing 3075.
During operation, the apparatus 3000 is preferably positioned in a wellbore with
the upper end 3235 of the casing 3075 positioned in an overlapping relationship with the
lower end of an existing wellbore casing. In a particularly preferred embodiment, the thin
30 wall section 3240 of the casing 3075 is positioned in opposing overlapping relation with
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the thin wall section and outer annular sealing member of the lower end of the existing
section of wellbore casing. In this manner, the radial expansion of the casing 3075 will
compress the thin wall sections and annular compressible members of the upper end 3235
of the casing 3075 and the lower end of the existing wellbore casing into intimate contact.
5 During the positioning of the apparatus 3000 in the wellbore, the casing 3000 is preferably
supported by the expansion cone 3070.
After positioning the apparatus 3000, a first fluidic material is then pumped into
the fluid passage 3080, The first fluidic material may comprise any number of
conventional commercially available materials such as, for example, drilling mud, water,
10 epoxy, cement, slag mix or lubricants. In apreferred embodiment, the first fluidic material
comprises a hardenabie fluidic sealing material such as, for example, cement, epoxy, or
slag mix in order to optimally provide a hardenabie outer annular body around the
expanded casing 3075.
The first fluidic material may be pumped into the fluid passage 3080 at operating
15 pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0 to 4,500
gallons/minute (0 to 310.264 bar and 0 to 17034.35 litres/minute). In a preferred
embodiment, the first fluidic material is pumped into the fluid passage 3080 at operating
pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1 ,200 gallons/minute
(0 to 241,316 bar and 0 to 4542.49 litres/minute) in order to optimally provide operating
20 efficiency.
The first fluidic material pumped into the fluid passage 3080 passes through the
fluid passages 3085, 3090, 3095, 3 100, and 3 105 and then outside of the apparatus 3000.
The first fluidic material then preferably fills the annular region between the outside of the
apparatus 3000 and the interior walls of the wellbore.
25 The plug 3230 is then introduced into the fluid passage 3080. The plug 3230
lodges in the throat passage 3225 and fluidicly isolates and blocks off the fluid passage
3100. In a preferred embodiment, a couple of volumes of a non-hardenable fluidic
material are then pumped into the fluid passage 3080 in order to remove any hardenabie
fluidic material contained within and to ensure that none of the fluid passages are blocked.
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A second fluidic material is then pumped into the fluid passage 3080. The second
fluidic material may comprise any number of conventional commercially available
materials such as, for example, water, drilling gases, drilling mud or lubricant. In a
preferred embodiment, the second fluidic material comprises a non-hardenable fluidic
5 material such as, for example, water, drilling mud, drilling gases, or lubricant in order to
optimally provide pressurization of the pressure chambers 3 1 75 and 3 1 90.
The second fluidic material may be pumped into the fluid passage 3080 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500 psi and 0
to 4,500 gallons/minute (0 to 3 1 0.264 bar and 0 to 1 7034.35 litres/minute) . In a preferred
10 embodiment, the second fluidic material is pumped into the fluid passage 3080 at
operating pressures and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200
gallons/minute (0 to 241.316 bar and 0 to 4542.49 litres/minute) in order to optimally
provide operational efficiency.
The second fluidic material pumped into the fluid passage 3080 passes through the
15 fluid passages 3085, 3090, 3095, 3100 and into the pressure chambers 3130 of the slips
3025, and into the pressure chambers 3 175 and 3 190. Continued pumping of the second
fluidic material pressurizes the pressure chambers 3130, 3175, and 3190.
The pressurization of the pressure chambers 3130 causes the hydraulic slip
members 3 140 to expand in the radial direction and grip the interior surface of the casing
20 3075. The casing 3075 is then preferably maintained in a substantially stationary position.
The pressurization of the pressure chambers 3 1 75 and 3 1 90 cause the first upper
sealing head 3030, first outer sealing mandrel 3040, second upper sealing head 3050,
second outer sealing mandrel 3060, and expansion cone 3 070 to move in an axial direction
relative to the casing 3075. In this manner, the expansion cone 3070 will cause the casing
25 3075 to expand in the radial direction, beginning with the lower end 3250 of the casing
3075.
During the radial expansion process, the casing 3075 is prevented from moving in
an upward direction by the slips 3025. A length of the casing 3075 is then expanded in
the radial direction through the pressurization of the pressure chambers 3 1 75 and 3190.
30 The length of the casing 3075 that is expanded during the expansion process will be
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proportional to the stroke length of the first upper sealing head 3030, first outer sealing
mandrel 3040, second upper sealing head 3050, and expansion cone 3070.
Upon the completion of a stroke, the operating pressure of the second fluidic
material is reduced and the first upper sealing head 3030, first outer sealing mandrel 3040,
5 second upper sealing head 3050, second outer sealing mandrel 3060, and expansion cone
3070 drop to their rest positions with the casing 3075 supported by the expansion cone
3070. The reduction in the operating pressure of the second fluidic material also causes
the spring bias 3 135 of the slips 3025 to pull the slip members 3 140 away from the inside
walls of the casing 3075.
10 The position of the drillpipe 3075 is preferably adjusted throughout the radial
expansion process in order to maintain the overlapping relationship between the thin
walled sections of the lower end of the existing wellbore casing and the upper end of the
casing 3235. In a preferred embodiment, the stroking of the expansion cone 3070 is then
repeated, as necessary, until the thin walled section 3240 of the upper end 3235 of the
15 casing 3075 is expanded into the thin walled section of the lower end of the existing
wellbore casing. In this manner, a wellbore casing is formed including two adjacent
sections of casing having a substantially constant inside diameter. This process may then
be repeated for the entirety of the wellbore to provide a wellbore casing thousands of feet
in length having a substantially constant inside diameter.
20 In a preferred embodiment, during the final stroke of the expansion cone 3070, the
slips 3025 are positioned as close as possible to the thin walled section 3240 of the upper
end 3235 of the casing 3075 in order minimize slippage between the casing 3075 and the
existing wellbore casing at the end of the radial expansion process. Alternatively, or in
addition, the outside diameter of the upper annular sealing member 3245 is selected to
25 ensure sufficient interference fit with the inside diameter of the lower end of the existing
casing to prevent axial displacement of the casing 3075 during the final stroke.
Alternatively, or in addition, the outside diameter of the lower annular sealing member
3260 is selected to provide an interference fit with the inside walls of the wellbore at an
earlier point in the radial expansion process so as to prevent further axial displacement of
30 the casing 3075. In this final alternative, the interference fit is preferably selected to
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permit expansion of the casing 3075 by pulling the expansion cone 3070 out of the
wellbore, without having to pressurize the pressure chambers 3 175 and 3 1 90.
During the radial expansion process, the pressurized areas of the apparatus 3000
are preferably limited to the fluid passages 3080, 3085, 3090, 3095, 3 100, 31 10, 31 15,
5 3 1 20, the pressure chambers 3130 within the slips 3025, and the pressure chambers 3 1 75
and 3190. No fluid pressure acts directly on the casing 3075. This permits the use of
operating pressures higher than the casing 3075 could normally withstand.
Once the casing 3075 has been completely expanded off of the expansion cone
3070, the remaining portions of the apparatus 3000 are removed from the wellbore. In a
10 preferred embodiment, the contact pressure between the deformed thin wall sections and
compressible annular members of the lower end of the existing casing and the upper end
3235 of the casing 3075 ranges from about 400 to 10,000 psi (27.58 to 689.476 bar) in
order to optimally support the casing 3075 using the existing wellbore casing.
In this manner, the casing 3075 is radially expanded into contact with an existing
16 section of casing by pressurizing the interior fluid passages 3080, 3085, 3090, 3095, 3100,
31 10, 31 15, and 3120, the pressure chambers 3130 of the slips 3025 and the pressure
chambers 3 1 75 and 3 1 90 of the apparatus 3000.
In a preferred embodiment, as required, the annular body of hardenable fluidic
material is then allowed to cure to form a rigid outer annular body about the expanded
20 casing 3075. In the case where the casing 3075 is slotted, the cured fluidic material
preferably permeates and envelops the expanded casing 3075. The resulting new section
of wellbore casing includes the expanded casing 3075 and the rigid outer annular body.
The overlapping joint between the pre-existing wellbore casing and the expanded casing
3075 includes the deformed thin wall sections and the compressible outer annular bodies.
25 The inner diameter of the resulting combined wellbore casings is substantially constant.
In this manner, a mono-diameter wellbore casing is formed. This process of expanding
overlapping tubular members having thin wall end portions with compressible annular
bodies into contact can be repeated for the entire length of a wellbore. In this manner, a
mono-diameter wellbore casing can be provided for thousands of feet in a subterranean
30 formation.
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In a preferred embodiment, as the expansion cone 3070 nears the upper end 3235
of the casing 3075, the operating flow rate of the second fluidic material is reduced in
order to minimize shock to the apparatus 3000. In an alternative embodiment, the
apparatus 3000 includes a shock absorber for absorbing the shock created by the
5 completion of the radial expansion of the casing 3075.
In a preferred embodiment, the reduced operating pressure of die second fluidic
material ranges from about 100 to 1,000 psi (6.8947 to 68.947 bar) as the expansion cone
3070 nears the end of the casing 3075 in order to optimally provide reduced axial
movement and velocity of the expansion cone 3070. In a preferred embodiment, the
10 operating pressure of the second fluidic material is reduced during the return stroke of the
apparatus 3000 to the range of about 0 to 500 psi (0 to 34.47 bar) in order minimize the
resistance to the movement of the expansion cone 3070 during the return stroke. In a
preferred embodiment, the stroke length of the apparatus 3 000 ranges from about 10 to 45
feet (3.048 to 13.716 metres) in order to optimally provide equipment that can be easily
15 handled by typical oil well rigging equipment and also minimize the frequency at which
the apparatus 3000 must be re-stroked.
In an alternative embodiment, at least a portion of one or both of the upper sealing
heads, 3030 and 3050, includes an expansion cone for radially expanding the casing 3075
during operation of the apparatus 3000 in order to increase the surface area of the casing
20 3075 acted upon during the radial expansion process. In this manner, the operating
pressures can be reduced.
Alternatively, the apparatus 3000 may be used to join a first section of pipeline to
an existing section of pipeline. Alternatively, the apparatus 3000 may be used to directly
line the interior of a wellbore with a casing, without the use of an outer annular layer of
25 a hardenable material. Alternatively, the apparatus 3000 may be used to expand a tubular
support member in a hole.
Referring now to Figure 21, an apparatus 3330 for isolating subterranean zones
will be described. A wellbore 3305 including a casing 3310 are positioned in a
subterranean formation 3315. The subterranean formation 3315 includes a number of
30 productive and non-productive zones, including a water zone 3320 and a targeted oil sand
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zone 3325. During exploration of the subterranean formation 3315, the wellbore 3305
may be extended in a well known manner to traverse the various productive and non-
productive zones, including the water zone 3320 and the targeted oil sand zone 3325.
In a preferred embodiment, in order to fluidicly isolate the water zone 3320 from
5 the targeted oil sand zone 3325, an apparatus 3330 is provided that includes one or more
sections of solid casing 3335, one or more external seals 3340, one or more sections of
slotted casing 3345, one or more intermediate sections of solid casing 3350, and a solid
shoe 3355.
The solid casing 3335 may provide a fluid conduit that transmits fluids and other
10 materials from one end of the solid casing 3335 to the other end of the solid casing 3335.
The solid casing 3335 may comprise any number of conventional commercially available
sections of solid tubular casing such as, for example, oilfield tubulars fabricated from
chromium steel or fiberglass. In a preferred embodiment, the solid casing 3335 comprises
oilfield tubulars available from various foreign and domestic steel mills.
15 The solid casing 3335 is preferably coupled to the casing 33 10. The solid casing
3335 may be coupled to the casing 3310 using any number of conventional commercially
available processes such as, for example, welding, slotted and expandable connectors, or
expandable solid connectors. In apreferred embodiment, the solid casing 3335 is coupled
to the casing 3310 by using expandable solid connectors. The solid casing 3335 may
20 comprise a plurality of such solid casings 3335.
The solid casing 3335 is preferably coupled to one more of the slotted casings
3345. The solid casing 3335 may be coupled to the slotted casing 3345 using any number
of conventional commercially available processes such as, for example, welding, or slotted
and expandable connectors. In a preferred embodiment, the solid casing 3335 is coupled
25 to the slotted casing 3345 by expandable solid connectors.
In a preferred embodiment, the casing 3335 includes one more valve members
3360 for controlling the flow of fluids and other materials within the interior region of the
casing 3335, In an alternative embodiment, during the production mode of operation, an
internal tubular string with various arrangements of packers, perforated tubing, sliding
30 sleeves, and valves may be employed within the apparatus to provide various options for
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commingling and isolating subterranean zones from each other while providing a fluid
path to the surface.
In a particularly preferred embodiment, the casing 3335 is placed into the wellbore
3305 by expanding the casing 3335 in the radial direction into intimate contact with the
5 interior walls of the wellbore 3305. The casing 3335 may be expanded in the radial
direction using any number of conventional commercially available methods. In a
preferred embodiment, the casing 3335 is expanded in the radial direction using one or
more of the processes and apparatus described within the present disclosure.
The seals 3340 prevent the passage of fluids and other materials within the annular
10 region 3365 between the solid casings 3335 and 3350 and the wellbore 3305. The seals
3340 may comprise any number of conventional commercially available sealing materials
suitable for sealing a casing in a wellbore such as, for example, lead, rubber or epoxy. In
a preferred embodiment, the seals 3340 comprise Stratalok epoxy material available from
Halliburton Energy Services.
15 The slotted casing 3345 permits fluids and other materials to pass into and out of
the interior of the slotted casing 3345 from and to the annular region 3365. In this
manner, oil and gas may be produced from a producing subterranean zone within a
subterranean formation. The slotted casing 3345 may comprise any number of
conventional commercially available sections of slotted tubular casing. In a preferred
20 embodiment, the slotted casing 3345 comprises expandable slotted tubular casing
available from Petroline in Abeerdeen, Scotland. In a particularly preferred embodiment,
the slotted casing 145 comprises expandable slotted sandscreen tubular casing available
from Petroline in Abeerdeen, Scotland.
The slotted casing 3345 is preferably coupled to one or more solid casing 3335.
25 The slotted casing 3345 may be coupled to the solid casing 3335 using any number of
conventional commercially available processes such as, for example, welding, or slotted
or solid expandable connectors. In a preferred embodiment the slotted casing 3345 is
coupled to the solid casing 3335 by expandable solid connectors.
The slotted casing 3345 is preferably coupled to one or more intermediate solid
0 casings 3350. The slotted casing 3345 may be coupled to the intermediate solid casing
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3350 using any number of conventional commercially available processes such as, for
example, welding or expandable solid or slotted connectors. In a preferred embodiment,
the slotted casing 3345 is coupled to the intermediate solid casing 3350 by expandable
solid connectors.
5 The last section of slotted casing 3345 is preferably coupled to the shoe 3355. The
last slotted casing 3345 may be coupled to the shoe 3355 using any number of
conventional commercially available processes such as, for example, welding or
expandable solid or slotted connectors. In a preferred embodiment, the last slotted casing
3345 is coupled to the shoe 3355 by an expandable solid connector.
10 In an alternative embodiment, the shoe 3355 is coupled directly to the last one of
the intermediate solid casings 3350.
In a preferred embodiment, the slotted casings 3345 are positioned within the
wellbore 3305 by expanding the slotted casings 3345 in a radial direction into intimate
contact with the interior walls of the wellbore 3305. The slotted casings 3345 may be
15 expanded in a radial direction using any number of conventional commercially available
processes. In a preferred embodiment, the slotted casings 3 345 are expanded in the radial
direction using one or more of the processes and apparatus disclosed in the present
disclosure with reference to Figures 14a-20.
The intermediate solid casing 3350 permits fluids and other materials to pass
20 between adjacent slotted casings 3345. The intermediate solid casing 3350 may comprise
any number of conventional commercially available sections of solid tubular casing such
as, for example, oilfield tubulars fabricated from chromium steel or fiberglass. In a
preferred embodiment, the intermediate solid casing 3350 comprises oilfield tubulars
available from foreign and domestic steel mills.
25 The intermediate solid casing 3350 is preferably coupled to one or more sections
of the slotted casing 3345. The intermediate solid casing 3350 may be coupled to the
slotted casing 3345 using any number of conventional commercially available processes
such as, for example, welding, or solid or slotted expandable connectors. In a preferred
embodiment, the intermediate solid casing 3350 is coupled to the slotted casing 3345 by
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expandable solid connectors. The intermediate solid casing 3350 may comprise a plurality
of such intermediate solid casing 3350.
In a preferred embodiment, each intermediate solid casing 3350 includes one more
valve members 3370 for controlling the flow of fluids and other materials within the
5 interior region of the intermediate casing 3350. In an alternative embodiment, as will be
recognized by persons having ordinary skill in the art and the benefit of the present
disclosure, during the production mode of operation, an internal tubular string with
various arrangements of packers, perforated tubing, sliding sleeves, and valves may be
employed within the apparatus to provide various options for commingling and isolating
10 subterranean zones from each other while providing a fluid path to the surface.
In aparticularly preferred embodiment, the intermediate casing 3350 is placed into
the wellbore 3305 by expanding the intermediate casing 3350 in the radial direction into
intimate contact with the interior walls of the wellbore 3305. The intermediate casing
3350 may be expanded in the radial direction using any number of conventional
15 commercially available methods.
In an alternative embodiment, one or more of the intermediate solid casings 3350
may be omitted. In an alternative preferred embodiment, one or more of the slotted
casings 3345 are provided with one or more seals 3340.
The shoe 3355 provides a support member for (he apparatus 3330. In this manner,
20 various production and exploration tools may be supported by the show 3350. The shoe
3350 may comprise any number of conventional commercially available shoes suitable for
use in a wellbore such as, for example, cement filled shoe, or an aluminum or composite
shoe. In a preferred embodiment, the shoe 3350 comprises an aluminum shoe available
from Halliburton. In a preferred embodiment, the shoe 3355 is selected to provide
25 sufficient strength in compression and tension to permit the use of high capacity
production and exploration tools.
In a particularly preferred embodiment, the apparatus 3330 includes a plurality of
solid casings 3335, a plurality of seals 3340, a plurality of slotted casings 3345, a plurality
of intermediate solid casings 3350, and a shoe 3355. More generally, the apparatus 3330
30 may comprise one or more solid casings 3335, each with one or more valve members
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3360, n slotted casings 3345, n-l intermediate solid casings 3350, each with one or more
valve members 3370, and a shoe 3355.
During operation of the apparatus 3330, oil and gas may be controllably produced
from the targeted oil sand zone 3325 using the slotted casings 3345. The oil and gas may
5 then be transported to a surface location using the solid casing 3335. The use of
intermediate solid casings 3350 with valve members 3370 permits isolated sections of the
zone 3325 to be selectively isolated for production. The seals 3340 permit the zone 3325
to be fluidicly isolated from the zone 3320. The seals 3340 further permits isolated
sections of the zone 3325 to be fluidicly isolated from each other. In this manner, the
10 apparatus 3330pennitsunwantedand/ornon-prodiictivesubterraneanzones tobe fluidicly
isolated.
In an alternative embodiment, as will be recognized by persons having ordinary
skill in the art and also having the benefit of the present disclosure, during the production
mode of operation, an internal tubular string with various arrangements of packers,
15 perforated tubing, sliding sleeves, and valves may be employed within the apparatus to
provide various options for commingling and isolating subterranean zones from each other
while providing a fluid path to the surface.
Referring to Figures 22a, 22b, 22c and 22d, an embodiment of an apparatus 3500
for forming a wellbore casing while drilling a wellbore will now be described. In a
20 preferred embodiment, the apparatus 3500 includes a support member 3505, a mandrel
35 10, a mandrel launcher 35 1 5, a shoe 3520, a tubular member 3525, a mud motor 3530,
a drill bit 3535, a first fluid passage 3540, a second fluid passage 3545, a pressure chamber
3550, a third fluid passage 3555, a cup seal 3560, a body of lubricant 3565, seals 3570,
and a releasable coupling 3600.
25 The support member 3505 is coupled to the mandrel 35 10. The support member
3505 preferably comprises an annular member having sufficient strength to cany and
support the apparatus 3500 within the wellbore 3575. In a preferred embodiment, the
support member 3505 further includes one or more conventional centralizers (not
illustrated) to help stabilize the apparatus 3500.
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The support member 3505 may comprise one or more sections of conventional
commercially available tubular materials such as, for example, oilfield country tubular
goods, low alloy steel, stainless steel or carbon steel. In a preferred embodiment, the
support member 3505 comprises coiled tubing or drillpipe in order to optimally permit the
5 placement of the apparatus 3500 within a non-vertical wellbore.
In a preferred embodiment, the support member 3 505 includes a first fluid passage
3540 for conveying fluidic materials from a surface location to the fluid passage 3545.
In a preferred embodiment, the first fluid passage 3540 is adapted to convey fluidic
materials such as water, drilling mud, cement, epoxy or slag mix at operating pressures
10 and flow rates ranging from about 0 to 10,000 psi and 0 to 3,000 gallons/minute (0 to
689.476 bar and 0 to 1 1,356.24 litres/minute).
The mandrel 35 10 is coupled to and supported by the support member 3505. The
mandrel 3510 is also coupled to and supports the mandrel launcher 3515 and tubular
member 3525. The mandrel 35 10 is preferably adapted to controllably expand in a radial
15 direction. The mandrel 3510 may comprise any number of conventional commercially
available mandrels modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the mandrel 3510 comprises a hydraulic expansion tool as
disclosed in U.S. Patent No. 5,348,095, the contents of which are incorporated herein by
reference, modified in accordance with the teachings of the present disclosure.
20 In a preferred embodiment, the mandrel 3510 includes one or more conical sections
for expanding the tubular member 3525 in the radial direction. In a preferred
embodiment, the outer surfaces of the conical sections of the mandrel 35 10 have a surface
hardness ranging from about 58 to 62 Rockwell C in order to optimally radially expand
the tubular member 3525.
25 In apreferred embodiment, the mandrel 35 1 0 includes a second fluid passage 3545
fluidicly coupled to the first fluid passage 3540 and the pressure chamber 3550 for
conveying fluidic materials from the first fluid passage 3540 to the pressure chamber
3550. In a preferred embodiment, the second fluid passage 3545 is adapted to convey
fluidic materials such as water, drilling mud. cement, epoxy or slag mix at operating
30 pressures and flow rates ranging from about 0 to 1 2,000 psi and 0 to 3,500 gallons/minute
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(Oto 827.38 bar and 0 to 13,248.94 litres/minute) in order to optimally provide operating
pressure for efficient operation.
The mandrel launcher 35 15 is coupled to the tubular member 3525, the mandrel
3510, and the shoe 3520. The mandrel launcher 3515 preferably comprises a tapered
5 annular member that mates with at a portion of at least one of the conical portions of the
outer surface of the mandrel 3510. In a preferred embodiment, the wall thickness of the
mandrel launcher is less than the wall thickness of the tubular member 3525 in order to
facilitate the initiation of the radial expansion process and facilitate the placement of the
apparatus in openings having tight clearances. In a preferred embodiment, the wall
10 thickness of the mandrel launcher 3515 ranges from about 50 to 100 % of the wall
thickness of the tubular member 3525 immediately adjacent to the mandrel launcher 35 1 5
in order to optimally faciliate the radial expansion process and facilitate the insertion of
the apparatus 3500 into wellbore casings and other areas with tight clearances.
The mandrel launcher 35 1 5 may be fabricated from any number of conventional
15 commercially available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel or stainless steel. In a preferred embodiment, the mandrel
launcher 35 15 is fabricated from oilfield country tubular goods ofhigher strength by lower
wall thickness than the tubular member 3525 in order to optimally provide a smaller
container having approximately the same burst strength as the tubular member 3525.
20 The shoe 3520 is coupled to the mandrel launcher 35 1 5 and thereleasable coupling
3600. The shoe 3520 preferably comprises a substantially annular member. In a preferred
embodiment, the shoe 3520 or the releasable coupling 3600 include a third fluid passage
3555 fluidicly coupled to the pressure chamber 3550 and the mud motor 3530.
The shoe 3520 may comprise any number of conventional commercially available
25 shoes such as, for example, cement filled, aluminum or composite modified in accordance
with the teachings of the present disclosure. In a preferred embodiment, the shoe 3520
comprises a high strength shoe having a burst strength approximately equal to the burst
strength of the tubular member 3525 and mandrel launcher 3515. The shoe 3520 is
preferably coupled to the mud motor 3520 by a releasable coupling 3600 in order to
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optimally provide for removal of the mud motor 3530 and drill nit 3535 upon the
completion of a drilling and casing operation.
In a preferred embodiment, the shoe 3520 includes a releasable latch mechanism
3600 for retrieving and removing the mud motor 3530 and drill bit 3535 upon the
5 completion of the drilling and casing formation operations. In a preferred embodiment,
the shoe 3520 further includes an anti-rotation device for maintaining the shoe 3520 in a
substantially stationary rotational position during operation of the apparatus 3500. In a
preferred embodiment, the releasable latch mechanism 3600 is releasably coupled to the
shoe 3520.
10 The tubular member 3525 is supported by and coupled to the mandrel 3510. The
tubular member 3525 is expanded in the radial direction and extruded off of the mandrel
3510. The tubular member 3525 may be fabricated from any number of conventional
commercially available materials such as, for example, Oilfield Country Tubular Goods
(OCTG), 13 chromium steel tubing/casing, automotive grade steel, or plastic
15 tubing/casing. In a preferred embodiment, the tubular member 3525 is fabricated from
OCTG in order to maximize strength after expansion. The inner and outer diameters of
the tubular member 3525 may range, for example, from approximately 0.75 to 47 inches
and 1.05 to 48 inches (1.905 to 119.38 centimetres and 2.667 to 121.92 centimetres),
respectively. In a preferred embodiment, the inner and outer diameters of the tubular
20 member 3525 range from about 3 to 15.5 inches and 3.5 to 16 inches (7.62 to 39.37
centimetres and 8.89 to 40.64 centimetres), respectively in order to optimally provide
minimal telescoping effect in the most commonly drilled wellbore sizes. The tubular
member 3525 preferably comprises an annular member with solid walls.
In apreferred embodiment, the upper endportion 3580 of the tubular member 3525
25 is slotted, perforated, or otherwise modified to catch or slow down the mandrel 3510 when
the mandrel 3510 completes the extrusion of tubular member 3525. For typical tubular
member 3525 materials, the length of the tubular member 3525 is preferably limited to
between about 40 to 20,000 feet (12.192 to 6096.00 metres) in length. The tubular
member 3525 may comprise a single tubular member or, alternatively, a plurality of
30 tubular members coupled to one another.
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The mud motor 3530 is coupled to the shoe 3520 and the drill bit 3535. The mud
motor 3530 is also fluidicly coupled to the fluid passage 3555. In a preferred embodiment,
the mud motor 3530 is driven by fluidic materials such as, for example, drilling mud,
water, cement, epoxy, lubricants or slag mix conveyed from the fluid passage 3555 to the
5 mud motor 3530. In this manner, the mud motor 3530 drives the drill bit 3535. The
operating pressures and flow rates for operating mud motor 3530 may range, for example,
from about 0 to 12,000 psi and 0 to 10,000 gallons/minute (0 to 827.37 bar and 0 to
37,854.12 litres/minute). In a preferred embodiment, the operating pressures and flow
rates for operating mud motor 3530 range from about 0 to 5,000 psi and 40 to 3,000
10 gallons/minute (0 to 344.74 bar and 151.42 to 1 1356.24 litres/minute).
The mud motor 3530 may comprise any number of conventional commercially
available mud motors, modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the size of the mud motor 3520 and drill bit 3535 are selected
to pass through the interior of the shoe 3520 and the expanded tubular member 3525. In
15 this manner, the mud motor 3520 and drill bit 3535 may be retrieved from the downhole
location upon the conclusion of the drilling and casing operations.
The drill bit 3535 is coupled to the mud motor 3530. The drill bit 3535 is
preferably adapted to be powered by the mud motor 3530. In this manner, the drill bit
3535 drills out new sections of the wellbore 3575.
20 The drill bit 3535 may comprise any number of conventional commercially
available drill bits, modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the size of the mud motor 3520 and drill bit 3535 are selected
to pass through the interior of the shoe 3520 and the expanded tubular member 3525. In
this manner, the mud motor 3520 and drill bit 3535 may be retrieved from the downhole
25 location upon the conclusion of the drilling and casing operations. In several alternative
preferred embodiments, the drill bit 3535 comprises an eccentric drill bit, a bi-centered
drill bit, or a small diameter drill bit with an hydraulically actuated under reamer.
The first fluid passage 3540 permits fluidic materials to be transported to the
second fluid passage 3545, the pressure chamber 3550, the third fluid passage 3555, and
30 the mud motor 3530. The first fluid passage 3540 is coupled to and positioned within the
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support member 3505. The first fluid passage 3540 preferably extends from a position
adjacent t the surface to the second fluid passage 3545 within the mandrel 3510. The
first fluid passage 3540 is preferably positioned along a centerline of the apparatus 3500.
The second fluid passage 3545 permits fluidic materials to be conveyed from the
5 first fluid passage 3540 to the pressure chamber 3550, the third fluid passage 3555, and
the mud motor 3530. The second fluid passage 3545 is coupled to and positioned within
the mandrel 3510. The second fluid passage 3545 preferably extends from a position
adjacent to the first fluid passage 3540 to the bottom of the mandrel 3510. The second
fluid passage 3545 is preferably positioned substantially along the centerline of the
10 apparatus 3500.
The pressure chamber 3550 permits fluidic materials to be conveyed from the
second fluid passage 3545 to the third fluid passage 3555, and the mud motor 3530. The
pressure chamber is preferably defined by the region below the mandrel 35 10 and within
the tubular member 3525, mandrel launcher 3515, shoe 3520, and releasable coupling
15 3600. During operation of the apparatus 3500, pressurization of the pressure chamber
3550 preferably causes the tubular member 3525 to be extruded off of the mandrel 3510.
The third fluid passage 3555 permits fluidic materials to be conveyed from the
pressure chamber 3550 to the mud motor 3530. The third fluid passage 3555 may be
coupled to and positioned within the shoe 3520 or releasable coupling 3600. The third
20 fluid passage 3555 preferably extends from a position adjacent to the pressure chamber
3550 to the bottom of the shoe 3520 or releasable coupling 3600. The third fluid passage
3555 is preferably positioned substantially along the centerline of the apparatus 3500.
The fluid passages 3540, 3545, and 3555 are preferably selected to convey
materials such as cement, drilling mud or epoxies at flow rates and pressures ranging from
25 about 0 to 3,000 gallons/minute and 0 to 9,000 psi (0 to 1 1356.24 litres/minute and 0 to
620.528 bar) in order to optimally operational efficiency.
The cup seal 3560 is coupled to and supported by the outer surface of the support
member 3505. The cup seal 3560 prevents foreign materials from entering the interior
region of the tubular member 3525. The cup seal 3560 may comprise any number of
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conventional commercially available cup seals such as, for example, TP cups or SIP cups
modified in accordance with the teachings of the present disclosure. In a preferred
embodiment, the cup seal 3560 comprises a SIP cup, available from Halliburton Energy
Services in Dallas, TX in order to optimally block the entry of foreign materials and
5 contain a body of lubricant. In a preferred embodiment, the apparatus 3500 includes a
plurality of such cup seals in order to optimally prevent the entry of foreign material into
the interior region of the tubular member 3525 in the vicinity of the mandrel 3510.
In a preferred embodiment, a quantity of lubricant 3565 is provided in the annular
region above the mandrel 3510 within the interior of the tubular member 3525. In this
10 manner, the extrusion of the tubular member 3525 off of the mandrel 35 10 is facilitated.
The lubricant 3565 may comprise any number of conventional commercially available
lubricants such as, for example, Lubriplate (RTM), chlorine based lubricants, oil based
lubricants or Climax 1500 Antisieze (3 100). In a preferred embodiment, the lubricant
3565 comprises Climax 1500 Antisieze (3100) available from Climax Lubricants and
15 Equipment Co. in Houston, TX in order to optimally provide optimum lubrication to
faciliate the expansion process.
The seals 3570 are coupled to and supported by the end portion 3580 of the tubular
member 3525. The seals 3570 are further positioned on an outer surface of the end portion
3580 of the tubular member 3525. The seals 3570 permit the overlapping joint between
20 the lower end portion 3585 of a preexisting section of casing 3590 and the end portion
3580 of the tubular member 3525 to be fluidicly sealed. The seals 3570 may comprise
any number of conventional commercially available seals such as, for example, lead,
rubber, Teflon (RTM), or epoxy seals modified in accordance with the teachings of the
present disclosure. Inapreferred embodiment, the seals 3570 are molded from Stratalock
25 epoxy available from Halliburton Energy Services in Dallas, TX in order to optimally
provide a load bearing interference fit between the end 3580 of the tubular member 3525
and the end 3585 of the pre-existing casing 3590.
In a preferred embodiment, the seals 3570 are selected to optimally provide a
sufficient frictional force to support the expanded tubular member 3525 from the pre-
30 existing casing 3590. In a preferred embodiment, the frictional force optimally provided
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by the seals 3570 ranges from about 1,000 to 1,000,000 lbf (0.478803 to 478.803 bar) in
order to optimally support the expanded tubular member 3525.
The releasable coupling 3600 is preferably releasably coupled to the bottom of the
shoe 3520. In a preferred embodiment, the releasable coupling 3600 includes fluidic seals
5 for sealing the interface between the releasable coupling 3600 and the shoe 3520. In this
manner, the pressure chamber 3550 may be pressurized. The releasable coupling 3600
may comprise any number of conventional commercially available releasable couplings
suitable for drilling operations modified in accordance with the teachings of the present
disclosure.
10 As illustrated in Figure 22A, during operation of the apparatus 3500, the apparatus
3500 is preferably initially positioned within a preexisting section of a wellbore 3575
including a preexisting section of wellbore casing 3590. In a preferred embodiment, the
upper end portion 3580 of the tubular member 3525 is positioned in an overlapping
relationship with the lower end 3585 of the preexisting section of casing 3590. In a
15 preferred embodiment, the apparatus 3500 is initially positioned in the wellbore 3575 with
the drill bit 353 in contact with the bottom of the wellbore 3575. During the initial
placement of the apparatus 3500 in the wellbore 3575, the tubular member 3525 is
preferably supported by the mandrel 3510.
As illustrated in Figure 22B, a fluidic material 3595 is then pumped into the first
20 fluid passage 3540. The fluidic material 3595 is preferably conveyed from the first fluid
passage 3540 to the second fluid passage 3545, the pressure chamber 3550, the third fluid
passage 3555 and the inlet to the mud motor 3530. The fluidic material 3595 may
comprise any number of conventional commercially available fluidic materials such as,
for example, drilling mud, water, cement, epoxy or slag mix. The fluidic material 3595
25 may be pumped into the first fluid passage 3540 at operating pressures and flow rates
ranging, for example, from about 0 to 9,000 psi and 0 to 3,000 gallons/minute (0 to
620.528 bar and 0 to 1 1356.24 litres/minute).
The fluidic material 3595 will enter the inlet for the mud motor 353 0 and drive the
mud motor 3530. The fluidic material 3595 will then exit the mud motor 3530 and enter
30 the annular region surrounding the apparatus 3500 within the wellbore 3575. The mud
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motor 3530 will in turn drive the drill bit 3535. The operation of the drill bit 3535 will
drill out a new section of the wellbore 3575.
In the case where the fluidic material 3 595 comprises a hardenable fluidic material,
the fluidic material 3595 preferably is permitted to cure and form an outer annular body
5 surrounding the periphery of the expanded tubular member 3525. Alternatively, in the
case where the fluidic material 3595 is a non-hardenable fluidic material, the tubular
member 3595 preferably is expanded into intimate contact with the interior walls of the
wellbore 3575. In this manner, an outer annular body is not provided in all applications.
As illustrated in Figure 22C, at some point during operation of the mud motor 3530
10 and drill bit 3535, the pressure drop across the mud motor 3530 will create sufficient back
pressure to cause the operating pressure within the pressure chamber 3550 to elevate to
the pressure necessary to extrude the tubular member 3525 off of the mandrel 3510. The
elevation of the operating pressure within the pressure chamber 3550 will then cause the
tubular member 3525 to extrude off of the mandrel 3510 as illustrated in Figure 22D. For
15 typical tubular members 3525, the necessary operating pressure may range, for example,
from about 1 ,000 to 9,000 psi (68.95 to 620.53 bar). In this manner, a wellbore casing is
formed simultaneous with the drilling out of a new section of wellbore.
In a particularly preferred embodiment, during the operation of the apparatus 3500,
the apparatus 3500 is lowered into the wellbore 3575 until the drill bit 3535 is proximate
20 the bottom of the wellbore 3575. Throughout this process, the tubular member 3525 is
preferably supported by the mandrel 35 1 0. The apparatus 3500 is then lowered until the
drill bit 3535 is placed in contact with the bottom of the wellbore 3575. At this point, at
least a portion of the weight of the tubular member 3525 is supported by the drill bit 3535.
The fluidic material 3595 is then pumped into the first fluid passage 3540, second
25 fluid passage 3545, pressure chamber 3550, third fluid passage 3555, and the inlet of the
mud motor 3530. The mud motor 3530 then drives the drill bit 3535 to drill out a new
section of the wellbore 3575. Once the differential pressure across the mud motor 3530
exceeds the minimum extrusion pressure for the tubularmember 3 525 , the tubul ar member
3525 begins to extrude off of the mandrel 35 1 0. As the tubular member 3525 is extruded
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off of the mandrel 351 0, the weight of the extruded portion of the tubular member 3525
is transferred to and supported by the drill bit 3535. In a preferred embodiment, the
pumping pressure of the fluidic material 3595 is maintained substantially constant
throughout this process. At some point during the process of extruding the tubular
5 member 3525 off of the mandrel 3510, a sufficient portion of the weight of the tubular
member 3525 is transferred to the drill bit 3535 to stop the extrusion process due to the
opposing force. Continued drilling by the drill bit 3535 eventually transfers a sufficient
portion of the weight of the extruded portion of the tubular member 3525 back to the
mandrel 35 1 0. At this point, the extrusion of the tubular member 3525 off of the mandrel
10 35 10 continues. In this manner, the support member 3505 never has to be moved and no
drillpipe connections have to be made at the surface since the new section of the wellbore
casing within the newly drilled section of wellbore is created by the constant downward
feeding of the expanded tubular member 3525 off of the mandrel 3510.
Once the new section of wellbore that is lined with the fully expanded tubular
15 member 3525 is completed, the support member 3505 and mandrel 3510 are removed
from the wellbore 3575. The drilling assembly including the mud motor 3530 and drill
bit 3535 are then preferably removed by lowering a drillstring into the new section of
wellbore casing and retrieving the drilling assembly by using the latch 3600. The
expanded tubular member 3525 is then cemented using conventional squeeze cementing
20 methods to provide a solid annular sealing member around the periphery of the expanded
tubular member 3525.
Alternatively, the apparatus 3500 may be used to repair or form an underground
pipeline or form a support member for a structure. In several preferred alternative
embodiments, the teachings of the apparatus 3500 are combined with the teachings of the
25 embodiments illustrated in Figures 1-21. For example, by operably coupling the mud
motor 3530 and drill bit 3535 to the pressure chambers used to cause the radial expansion
of the tubular members of the embodiments illustrated and described with reference to
Figures 1 -2 1 , the use of plugs may be eliminated and radial expansion of tubular members
can be combined with the drilling out of new sections of wellbore.
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Claims
1 . A method of creating a casing in a borehole located in a subterranean formation,
comprising:
installing a tubular liner and a mandrel in the borehole;
5 injecting fluidic material into the borehole;
pressurizing a portion of an interior region of the tubular liner;
radially expanding at least a portion of the liner in the borehole by extruding at
least a portion of the liner off of the mandrel; and
drilling out the borehole while extruding the liner off of the mandrel.
10 2. A method of joining a second tubular member to a first tubular member, the first
tubular member having an inner diameter greater than an outer diameter of the second
tubular member, comprising:
positioning a mandrel within an interior region of the second tubular member;
pressurizing a portion of the interior region of the second tubular member,
15 extruding at least a portion of the second tubular member off of the mandrel into
engagement with the first tubular member, and
drilling out the borehole while extruding the second tubular member off
of the mandrel.
3. A method of joining a second tubular member to a first tubular member, the first
20 tubular member having an inner diameter greater than an outer diameter of the second
tubular member, comprising:
positioning a mandrel within an interior region of the second tubular member;
pressurizing a portion of the interior region of the mandrel ;
displacing the mandrel relative to the second tubular member;
25 extruding at least a portion of the second tubular member ofT of the mandrel into
engagement with the first tubular member: and
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1
drilling out the borehole while extruding the second tubular member off
of the mandrel.
4. The method of claim 1, wherein the injecting includes:
injecting a non hardenable fluidic material into an interior region of the tubular
5 liner below the mandrel.
5. The method of claim 4, further comprising:
fluidicly isolating the annular region from the interior region before injecting the
non hardenable fluidic material into the interior region.
6. The method of claim 1 , further comprising:
10 maintaining the mandrel in a substantially stationary position within the borehole
during the extrusion of the liner and the drilling out of the bore hole.
7. The method of claim 4, wherein the injecting of the non hardenable fluidic
material is provided at operating pressures and flow rates ranging from about 500 to 9,000
psi and 40 to 3,000 gallons/min (34.47 to 620.53 bar and 151.42 to 113562.24
15 litres/minute).
8 . The method of claim 4, wherein the injecting of the non hardenable fluidic material
is provided at reduced operating pressures and flow rates during an end portion of the
extruding.
9. The method of claim 1 , wherein the fluidic material is injected below the mandrel.
20 10. The method of claim 1 , wherein a region of the tubular liner below the mandrel is
pressurized.
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11. The method of claim 1 0, wherein the region of the tubular liner below the mandrel
is pressurize to pressures ranging from about 500 to 9,000 psi (34.47 to 620.53 bar)
12. The method of claim 1, further comprising:
fluidicly isolating an interior region of the tubular liner from an exterior region of
5 the tubular liner.
1 3 . The method of claim 1 2, wherein the interior region of the tubular liner is isolated
from the region exterior to the tubular liner by inserting one or more plugs into the
injected fluidic material.
14. The method of claim 1 , further comprising:
0 injecting a hardenable fluidic sealing material into the annulus between the
extruded liner and the borehole.
1 5 . The method of claim 1 , further comprising:
overlapping the tubular liner with an existing wellbore casing.
1 6. The method of claim 1 5, further comprising:
> sealing the overlap between the tubular liner and the existing wellbore casing.
1 7. The method of claim 1 6, further comprising:
supporting the extruded tubular liner using the overlap with the existing wellbore
casing.
1 8 . The method of claim 1 6, further comprising:
► testing the integrity of the seal in the overlap between the tubular liner and the
existing wellbore casing.
1 9 . The method of claim 1 , further comprising:
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applying a variable axial force onto the bottom of the borehole.
20.
The method of claim 1, further comprising:
lubricating the surface of the mandrel
5
21.
The method of claim 1 , further comprising:
absorbing shock.
22. The method of claim 1, further comprising:
catching the mandrel upon the completion of the extruding.
23. The method of claim 1, further comprising expanding the mandrel in a radial
direction.
10 24. The method of claim 1, further comprising:
drilling out the mandrel.
25. The method of claim 1, further comprising:
supporting the mandrel with coiled tubing.
26. The method of claim 1, wherein the wall thickness of the tubular member is
15 variable.
27. The method of claim 1 , wherein the mandrel is coupled to a drillable shoe.
28. The method of claim 2 or 3, wherein the pressurizing of the portion of the interior
region of the second tubular member is provided at operating pressures ranging from about
500 to 9,000 psi (34.47 to 620.53 bar).
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29. The method of claim 2 or 3, wherein the pressurizing of the portion of the interior
region of the second tubular member is provided at reduced operating pressures during a
latter portion of the extruding.
30. The method of claim 2 or 3, further comprising:
5 sealing the interface between the first and second tubular members.
3 1 . The method of claim 2 or 3 , further comprising:
supporting the extruded second tubular member using the interface with the first
tubular member.
32. The method of claim 2 or 3, further comprising:
10 lubricating the surface of the mandrel.
33. The method of claim 2 or 3, further comprising:
absorbing shock.
34. The method of claim 2 or 3, further comprising:
expanding the mandrel in a radial direction.
15 35. The method of claims 2 or 3, further comprising:
positioning the first and second tubular members in an overlapping relationship.
36. The method of claim 2 or 3, further comprising:
fluidicly isolating an interior region of the second tubular member from an exterior
region of the second tubular member.
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37. The method of claim 36, wherein the interior region of the second tubular member
is fluidicly isolated from the region exterior to the second tubular member by injecting one
or more plugs into the interior of the second tubular member.
38. The method of claim 2 or 3, wherein the pressurizing of the portion of the interior
5 region of the second tubular member is provided by injecting a fluidic material at
operating pressures and flow rates ranging from about 500 to 9,000 psi and 40 to 3,000
gallons/minute (34.47 to 620.53 bar and 151.42 to 11356.24 litres/minute).
39. The method of claim 2 or 3, further comprising:
injecting fluidic material beyond the mandrel.
10 40. The method of claim 2 or 3, wherein a region of the second tubular member
beyond the mandrel is pressurized.
4 1 . The method of claim 40, wherein the region of the second tubular member beyond
the mandrel is pressurized to pressures ranging from about 500 to 9,000 psi (34.47 to
620.53 bar).
15 42. The method of claim 2 or 3, wherein the first tubular member comprises an existing
section of a wellbore.
43 . The method of claim 2 or 3, further comprising:
sealing the interface between the first and second tubular members.
44. The method of claim 2 or 3, further comprising:
20 supporting the extruded second tubular member using the first tubular member.
45. The method of claim 43, further comprising:
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1
testing the integrity of the seal in the interface between the first tubular member
and the second tubular member.
46. The method of claim 2 or 3, further comprising:
catching the mandrel upon the completion of the extruding.
5 47. The method of claim 2 or 3, further comprising:
drilling out the mandrel.
48. The method of claim 2 or 3, further comprising:
supporting the mandrel with coiled tubing.
49. The method of claim 2 or 3, further comprising:
10 coupling the mandrel to a drillable shoe.
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